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 December 31, 2016

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

For the transition period from to

Commission File Number 001-31759

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)

OKLAHOMA	73-1055775
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Grand Centre Suite 300, 5400 N Grand Blvd., Oklahoma City, Oklahoma  73112

(Address of principal executive offices)

Registrant's telephone number including area code (405) 948-1560

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  ☑    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes  ☑    No  ☐

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes  ☐    No  ☑

Outstanding shares of Class A Common stock (voting) at February 6, 2017: 16,640,048

INDEX

Part I	Financial Information		Page
	Item 1	Condensed Financial Statements	1
		Condensed Balance Sheets – December 31, 2016, and September 30, 2016	1
		Condensed Statements of Operations – Three months ended December 31, 2016 and 2015	2
		Statements of Stockholders’ Equity – Three months ended December 31, 2016 and 2015	3
		Condensed Statements of Cash Flows – Three months ended December 31, 2016 and 2015	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	17
	Item 4	Controls and procedures	18
Part II	Other Information
	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	18
	Item 6	Exhibits and reports on Form 8-K	19
	Signatures		19

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.

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

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

“FASB” the Financial Accounting Standards Board.

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

“G&A” general and administrative costs.

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

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

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

“IDC” intangible drilling costs.

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

“LOE” lease operating expense.

“Mcf” thousand cubic feet.

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

“Mmbtu” million BTU.

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

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

“NGL” natural gas liquids.

“NYMEX” New York Mercantile Exchange.

“Panhandle” Panhandle Oil and Gas Inc.

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

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

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

“SEC” the United States Securities and Exchange Commission.

“undeveloped acreage” lease 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 2017 mean the fiscal year ended September 30, 2017.

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

	December 31, 2016			September 30, 2016
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	484,989		$	471,213
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)		5,526,787			5,287,229
Refundable income taxes		98,040			83,874
Other		273,397			419,037
Total current assets		6,383,213			6,261,353
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		437,851,114			434,469,093
Non-producing oil and natural gas properties		7,538,806			7,574,649
Other		1,068,778			1,069,658
		446,458,698			443,113,400
Less accumulated depreciation, depletion and amortization		(256,491,564	)		(251,707,749	)
Net properties and equipment		189,967,134			191,405,651
Investments		172,352			157,322
Total assets	$	196,522,699		$	197,824,326
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	3,457,200		$	2,351,623
Derivative contracts, net		2,933,947			403,612
Accrued liabilities and other		1,968,967			1,718,558
Total current liabilities		8,360,114			4,473,793
Long-term debt		44,100,000			44,500,000
Deferred income taxes, net		29,569,007			30,676,007
Asset retirement obligations		2,990,823			2,958,048
Derivative contracts, net		10,587			24,659
Stockholders' equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized,    16,863,004 issued at December 31, 2016, and September 30, 2016		280,938			280,938
Capital in excess of par value		2,476,066			3,191,056
Deferred directors' compensation		3,509,031			3,403,213
Retained earnings		108,903,533			112,482,284
		115,169,568			119,357,491
Less treasury stock, at cost; 223,661 shares at December 31, 2016, and 262,708 shares at September 30, 2016		(3,677,400	)		(4,165,672	)
Total stockholders' equity		111,492,168			115,191,819
Total liabilities and stockholders' equity	$	196,522,699		$	197,824,326

(See accompanying notes)

(1)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

	Three Months Ended December 31,
	2016			2015
Revenues:	(unaudited)
Oil, NGL and natural gas sales	$	8,899,218		$	9,055,288
Lease bonuses and rentals		837,958			2,425,504
Gains (losses) on derivative contracts		(2,700,533	)		(34,936	)
Income (loss) from partnerships		15,030			16,269
		7,051,673			11,462,125
Costs and expenses:
Lease operating expenses		3,049,415			3,566,536
Production taxes		367,845			321,841
Exploration costs		(2,243	)		27,790
Depreciation, depletion and amortization		4,834,263			6,957,652
Provision for impairment		-			3,733,273
Loss (gain) on asset sales and other		12,934			(269,706	)
Interest expense		292,369			360,562
General and administrative		1,842,482			1,912,079
Bad debt expense (recovery)		-			19,216
		10,397,065			16,629,243
Income (loss) before provision (benefit) for income taxes		(3,345,392	)		(5,167,118	)
Provision (benefit) for income taxes		(1,107,000	)		(2,368,000	)
Net income (loss)	$	(2,238,392	)	$	(2,799,118	)
Basic and diluted earnings (loss) per common share (Note 3)	$	(0.13	)	$	(0.17	)
Basic and diluted weighted average shares outstanding:
Common shares		16,604,149			16,563,942
Unissued, directors' deferred compensation shares		274,035			255,060
		16,878,184			16,819,002
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

(See accompanying notes)

(2)

PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Three Months Ended December 31, 2016

	Class A voting				Capital in			Deferred
	Common Stock				Excess of			Directors'		Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation		Earnings			Shares			Stock			Total
Balances at September 30, 2016		16,863,004	$	280,938	$	3,191,056		$	3,403,213	$	112,482,284			(262,708	)	$	(4,165,672	)	$	115,191,819
Purchase of treasury stock		-		-		-			-		-			(17,119	)		(407,677	)		(407,677	)
Restricted stock awards		-		-		180,412			-		-			-			-			180,412
Net income (loss)		-		-		-			-		(2,238,392	)		-			-			(2,238,392	)
Dividends ($.08 per share)		-		-		-			-		(1,340,359	)		-			-			(1,340,359	)
Distribution of restricted stock to    officers and directors		-		-		(895,402	)		-		-			56,166			895,949			547
Increase in deferred directors'    compensation charged to    expense		-		-		-			105,818		-			-			-			105,818
Balances at December 31, 2016		16,863,004	$	280,938	$	2,476,066		$	3,509,031	$	108,903,533			(223,661	)	$	(3,677,400	)	$	111,492,168
(unaudited)

Three Months Ended December 31, 2015

	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, 2015		16,863,004	$	280,938	$	2,993,119		$	3,084,289	$	125,446,473			(302,623	)	$	(4,800,144	)	$	127,004,675
Purchase of treasury stock		-		-		-			-		-			(7,477	)		(117,165	)		(117,165	)
Restricted stock awards		-		-		371,407			-		-			-			-			371,407
Net income (loss)		-		-		-			-		(2,799,118	)		-			-			(2,799,118	)
Dividends ($.08 per share)		-		-		-			-		(1,337,982	)		-			-			(1,337,982	)
Distribution of restricted stock to    officers and directors		-		-		(449,307	)		-		-			25,507			404,541			(44,766	)
Increase in deferred directors'    compensation charged to    expense		-		-		-			85,930		-			-			-			85,930
Balances at December 31, 2015		16,863,004	$	280,938	$	2,915,219		$	3,170,219	$	121,309,373			(284,593	)	$	(4,512,768	)	$	123,162,981
(unaudited)

(See accompanying notes)

(3)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS

	Three months ended December 31,
	2016			2015
Operating Activities	(unaudited)
Net income (loss)	$	(2,238,392	)	$	(2,799,118	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		4,834,263			6,957,652
Impairment		-			3,733,273
Provision for deferred income taxes		(1,107,000	)		(3,747,000	)
Exploration costs		(2,243	)		27,790
Gain from leasing fee mineral acreage		(837,732	)		(2,425,131	)
Proceeds from leasing fee mineral acreage		847,578			2,693,812
Net (gain) loss on sales of assets		-			(271,080	)
Amortization of partnerships		2,541			19,984
Directors' deferred compensation expense		105,818			85,930
Restricted stock awards		180,412			371,407
Bad debt expense (recovery)		-			19,216
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables		(239,558	)		2,335,449
Fair value of derivative contracts		2,516,263			3,574,650
Refundable production taxes		-			1,162
Other current assets		145,640			(659,324	)
Accounts payable		(90,474	)		(484,882	)
Income taxes receivable		(14,166	)		345,897
Income taxes payable		-			1,073,551
Accrued liabilities		(419,299	)		(509,208	)
Total adjustments		5,922,043			13,143,148
Net cash provided by operating activities		3,683,651			10,344,030
Investing Activities
Capital expenditures, including dry hole costs		(2,174,523	)		(1,286,114	)
Investments in partnerships		(17,571	)		44,842
Proceeds from sales of assets		-			627,547
Net cash provided (used) by investing activities		(2,192,094	)		(613,725	)
Financing Activities
Borrowings under debt agreement		4,436,304			2,958,515
Payments of loan principal		(4,836,304	)		(10,958,515	)
Purchases of treasury stock		(407,677	)		(117,165	)
Payments of dividends		(670,104	)		(668,364	)
Excess tax benefit on stock-based compensation		-			(45,000	)
Net cash provided (used) by financing activities		(1,477,781	)		(8,830,529	)
Increase (decrease) in cash and cash equivalents		13,776			899,776
Cash and cash equivalents at beginning of period		471,213			603,915
Cash and cash equivalents at end of period	$	484,989		$	1,503,691
Supplemental Schedule of Noncash Investing and Financing Activities:
Dividends declared and unpaid	$	670,255		$	669,618
Additions to asset retirement obligations	$	594		$	4,524
Gross additions to properties and equipment	$	3,370,574		$	3,455,245
Net (increase) decrease in accounts payable for properties and equipment additions		(1,196,051	)		(2,169,131	)
Capital expenditures and acquisitions, including dry hole costs	$	2,174,523		$	1,286,114

(See accompanying notes)

(4)

PANHANDLE OIL AND GAS INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: Basis of Presentation and Accounting Principles

Basis of Presentation

The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the SEC. Management of the Company believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The results are not necessarily indicative of those to be expected for the full year. The Company’s fiscal year runs from October 1 through September 30.

Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s 2016 Annual Report on Form 10-K.

Adoption of New Accounting Pronouncements

In April 2015, the FASB issued Accounting Standards Update (“ASU”) 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The update requires that debt issuance costs related to a recognized debt liability, such as senior notes, term loans and note payables, be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with the presentation of debt discounts. Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset. The recognition and measurement guidance for debt issuance costs is not affected by the update. For public entities, the guidance is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years.

In August 2015, the FASB issued ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, which allows for line-of-credit arrangements to be handled consistently with the presentation of debt issuance costs prior to ASU 2015-03 issued in April 2015. For public entities, the guidance is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years.

The Company adopted ASU 2015-03 and ASU 2015-15 as of December 31, 2016. The Company elected to continue to show debt issuance costs associated with its credit facility (Company’s only debt) as assets versus a direct reduction of the debt liability. Therefore, the adoption had no impact on the Company's current and previously reported balance sheets, shareholders' equity, results of operations, or cash flows. In accordance with ASU 2015-15, unamortized debt issuance costs associated with the Company's credit facility, which amounted to $232,928 and $263,584 as of December 31, 2016, and September 30, 2016, respectively, remain reflected in "Other property and equipment" on the balance sheets.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. The update requires that deferred income tax assets and liabilities be classified as noncurrent in the balance sheet. For public entities, the guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years.

The Company early adopted ASU 2015-17 as of December 31, 2016, on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $201,900 and $310,900 as of December 31, 2016, and September 30, 2016, respectively, from "Deferred income taxes" in current assets to “Deferred income tax, net” in long term liabilities on the balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2015-17.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which addresses certain issues where diversity in practice was identified and may change how an entity classifies certain cash receipts and cash payments on its statement of cash flows. The new guidance also clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. This guidance will generally be applied retrospectively and is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption is permitted. All of the amendments in ASU 2016-15 are required to be adopted at the same time.

(5)

The Company early adopted ASU 2016-15 as of December 31, 2016. As a result of the adoption, the Company reclassified “Proceeds from leasing fee mineral acreage”, which totaled $847,578 and $2,693,812 as of December 31, 2016, and December 31, 2015, respectively, from Investing Activities to Operating Activities on the Condensed Statements of Cash Flows as these transactions are made in our normal course of business and represent operating activities based on the application of the predominance principle. As another result of this adoption, we are also electing to classify our distributions received from equity method investments using the Cumulative Earnings Approach. Distributions received are considered returns on investment and classified as cash inflows from operating activities, unless the investor’s cumulative distributions received less distributions received in prior periods that were determined to be returns of investment exceed cumulative equity in earnings recognized by the investor. When such an excess occurs, the current-period distribution up to this excess should be considered a return of investment and classified as cash inflows from investing activities. This election did not have any impact on our cash flow statements as the Company was already applying this approach. Adoption of ASU 2016-15 had no impact on the Company's current and previously reported shareholders' equity, results of operations or balance sheets. The affected prior period balances in the Condensed Statements of Cash Flows presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2016-15.

In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The new guidance is intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. The guidance changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, and will be adopted either prospectively, retrospectively or using a modified retrospective transition approach depending on the topic covered in the standard. Early adoption is permitted for any organization in any interim or annual period. On a prospective basis companies will no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies will be recognized as income tax expense or benefit in the income statement. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. Also, companies will have to present excess tax benefits and deficiencies as operating activities on the statement of cash flows (prospectively or retrospectively). The new guidance will also require an employer to classify as a financing activity in its statement of cash flows the cash paid to a tax authority when shares are withheld to satisfy the employer’s statutory income tax withholding obligation.

The Company early adopted ASU 2016-09 as of October 1, 2016. As a result of the adoption, the Company recorded $228,000 of excess tax benefits from stock-based compensation in the “Provision (benefit) for income taxes” on the Condensed Statements of Operations in the current period versus “Capital in excess of par” on the Condensed Balance Sheets as was previously required. This part of the guidance is to be applied prospectively, so the prior period balances have not been reclassified. The Company also presented excess tax benefits from stock-based compensation in the “Operating Activities” section of the Condensed Statements of Cash Flows in the current period versus the “Financing Activities” section of the Condensed Statements of Cash Flows as was previously presented. The Company has elected to apply this part of the guidance prospectively, so the prior period balances have not been reclassified. The guidance also requires that companies present employees taxes paid upon vesting as financing activities on the statement of cash flows. This requirement had no impact on the Company, as this has been the practice historically. The Company is also electing to account for forfeitures of awards as they occur, instead of estimating a forfeiture amount. A cumulative-effect adjustment to retained earnings was not necessary for this transition as there were no material forfeitures estimated or incurred in the past.

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842). Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date: 1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and 2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new lease guidance simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. Lessees will no longer be provided with a source of off-balance sheet financing. For public entities, the guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this update will have on our financial statements.

(6)

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The new guidance is intended to improve the recognition and measurement of financial instruments. The new guidance is effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. We are assessing the potential impact that this update will have on our financial statements.

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

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

NOTE 2: Income Taxes

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis.

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 are not directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the quarter ended December 31, 2016, was 33% as compared to 46% for the quarter ended December 31, 2015.

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

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

NOTE 4: Long-term Debt

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a current borrowing base of $80,000,000 and a maturity date of November 30, 2018. 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 with a net book value of $162,622,006 at December 31, 2016. The interest rate is based on BOK prime plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. 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 a larger percent of the borrowing base is advanced. At December 31, 2016, the effective interest rate was 2.81%.

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 (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. In December 2016, the borrowing base was redetermined by the banks and left unchanged at $80,000,000. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of

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indebtedness, liens, payment of dividends and acquisitions of treasury stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined – 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) of no more than 4.0 to 1.0. At December 31, 2016, the Company was in compliance with the covenants of the loan agreement and has $35,900,000 of availability under its outstanding credit facility.

NOTE 5: Deferred Compensation Plan for Non-Employee Directors

Annually, non-employee directors may elect to be included in the Deferred Compensation Plan for Non-Employee Directors. The Deferred Compensation Plan for Non-Employee Directors provides that each outside director may individually elect to be credited with future unissued shares of Company common stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees, and may elect to receive shares, when issued, over annual time periods up to ten years. 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 under the Deferred Compensation Plan for Non-Employee Directors be issued to the director. The promise to issue such shares in the future is an unsecured obligation of the Company.

NOTE 6: Restricted Stock Plan

In March 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 200,000 shares of common stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. In March 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, as amended, is designed to provide as much flexibility as possible for future grants of restricted stock so that the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate directors and officers of the Company and to align their interests with those of the Company’s shareholders.

Effective in May 2014, the board of directors adopted resolutions to allow management, at their discretion, to purchase the Company’s common stock 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.

On December 9, 2016, the Company awarded 6,845 non-performance based shares and 20,531 performance based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of a three-year period and contains non-forfeitable rights to receive dividends and voting rights during the vesting period. The non-performance and performance based shares had a fair value on their award date of $176,260 and $292,884, respectively. The fair value for the performance and the non-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 9, 2016, through December 9, 2019).

On December 31, 2016, the Company awarded 7,430 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, 2017. The restricted stock contains non-forfeitable rights to receive dividends and voting rights during the vesting period. These non-performance based shares had a fair value on their award date of $174,975.

The following table summarizes the Company’s pre-tax compensation expense for the three months ended December 31, 2016 and 2015, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended
	December 31,
	2016		2015
Performance based, restricted stock	$	79,216	$	269,510
Non-performance based, restricted stock		101,196		101,897
Total compensation expense	$	180,412	$	371,407

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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 December 31, 2016
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	421,524		2.37
Non-performance based, restricted stock		454,090		1.87
Total	$	875,614

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

NOTE 7: 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 geological and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing 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.

NOTE 8: Impairment

All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as: inflation rates; future 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 the three months ended December 31, 2016 and 2015, the assessment resulted in impairment provisions on producing properties of $0 and $3,733,273, respectively. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company.

NOTE 9: Capitalized Costs

As of December 31, 2016, and September 30, 2016, non-producing oil and natural gas properties include costs of $0 and $5,917, respectively, on exploratory wells which were drilling and/or testing.

NOTE 10: 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

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financial loss and limit the benefit of future increases in prices.All of the Company’s derivative contracts are with Bank of Oklahoma and are secured under its credit facility with Bank of Oklahoma.The derivative instruments have settled or will settle based on the prices below.

Derivative contracts in place as of December 31, 2016

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.65 ceiling
November 2016 - March 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.95 ceiling
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.60 floor / $3.25 ceiling
January - March 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.20 floor / $4.00 ceiling
January - June 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.85 floor / $3.35 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.47 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.65 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.60 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.20 floor / $3.65 ceiling
January - March 2018	100,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $3.95 ceiling
Natural gas fixed price swaps
October 2016 - March 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.200
November 2016 - April 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.955
January - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.665
January - December 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.100
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.070
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.210
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.300
July - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.510
January - March 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.700
Oil costless collars
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$40.00 floor / $58.50 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $54.00 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $55.50 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$50.00 floor / $55.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$52.00 floor / $58.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$53.00 floor / $57.75 ceiling
April - December 2017	2,000 Bbls	NYMEX WTI	$50.00 floor / $57.50 ceiling
July - December 2017	5,000 Bbls	NYMEX WTI	$45.00 floor / $56.25 ceiling
Oil fixed price swaps
January - December 2017	3,000 Bbls	NYMEX WTI	$53.89
April - June 2017	5,000 Bbls	NYMEX WTI	$53.50
April - December 2017	2,000 Bbls	NYMEX WTI	$54.20

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Derivative contracts in place as of September 30, 2016

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
April - October 2016	200,000 Mmbtu	NYMEX Henry Hub	$1.95 floor / $2.40 ceiling
October - December 2016	70,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.05 ceiling
October - December 2016	50,000 Mmbtu	NYMEX Henry Hub	$2.90 floor / $3.40 ceiling
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.65 ceiling
November 2016 - March 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.95 ceiling
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.60 floor / $3.25 ceiling
January - June 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.85 floor / $3.35 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.47 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
Natural gas fixed price swaps
October 2016	100,000 Mmbtu	NYMEX Henry Hub	$2.410
October 2016 - March 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.200
November 2016 - April 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.955
January - December 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.100
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.070
Oil costless collars
July - December 2016	3,000 Bbls	NYMEX WTI	$35.00 floor / $49.00 ceiling
October - December 2016	3,000 Bbls	NYMEX WTI	$40.00 floor / $47.25 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$40.00 floor / $58.50 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $54.00 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $55.50 ceiling

The Company has elected not to complete all of the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net liability of $2,944,534 as of December 31, 2016, and a net liability of $428,271 as of September 30, 2016.

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, 2016, and September 30, 2016. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at December 31, 2016, and September 30, 2016.

	December 31, 2016				September 30, 2016
	Fair Value (a)				Fair Value (a)
	Commodity Contracts				Commodity Contracts
	Current Liabilities		Non-Current Liabilities		Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities
Gross amounts recognized	$	2,933,947	$	10,587	$	68,235		$	471,847		$	4,759		$	29,418
Offsetting adjustments		-		-		(68,235	)		(68,235	)		(4,759	)		(4,759	)
Net presentation on Condensed Balance Sheets	$	2,933,947	$	10,587	$	-		$	403,612		$	-		$	24,659

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

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

NOTE 11: 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 December 31, 2016.

	Fair Value Measurement at December 31, 2016
	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	$	-	$	(1,138,750	)	$	-		$	(1,138,750	)
Derivative Contracts - Collars	$	-	$	-		$	(1,805,784	)	$	(1,805,784	)

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

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

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

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

Instrument Type	Unobservable Input	Range	Weighted Average		Fair Value December 31, 2016
Oil Collars	Oil price volatility curve	0% - 27.38%		18.53%	$	(493,394	)
Natural Gas Collars	Gas price volatility curve	0% - 39.17%		21.87%	$	(1,312,390	)

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

	Derivatives
Balance of Level 3 as of October 1, 2016	$	(316,658	)
Total gains or (losses)
Included in earnings		(1,349,636	)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(139,490	)
Transfers in and out of Level 3		-
Balance of Level 3 as of December 31, 2016	$	(1,805,784	)

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

	Quarter Ended December 31,
	2016				2015
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	3,152,454	$	3,733,273

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

At December 31, 2016, and September 30, 2016, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which the valuation is classified as Level 3 and is based on a valuation technique that requires inputs that are both unobservable and significant to the overall fair value measurement. The fair value measurement of our long-term debt is valued using a discounted cash flow model that calculates the present value of future cash flows pursuant to the terms of the debt agreements and applies estimated current market interest 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.

ITEM2 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

Forward-Looking Statements for fiscal 2017 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 2016 Annual Report on Form 10-K where risk factors are presented and further discussed. For all the above reasons, actual results may vary materially from the Forward-Looking Statements and there is no assurance that the assumptions used are necessarily the most likely to occur.

LIQUIDITY AND CAPITAL RESOURCES

The Company had negative working capital of $1,976,901 at December 31, 2016, compared to positive working capital of $1,787,560 at September 30, 2016. The change in working capital was mainly due to the derivative contracts liability increasing as of December 31, 2016.

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Liquidity:

Cash and cash equivalents were $484,989 as of December 31, 2016, compared to $471,213 at September 30, 2016, an increase of $13,776. Cash flows for the three months ended December 31 are summarized as follows:

Net cash provided (used) by:

	2016			2015			Change
Operating activities	$	3,683,651		$	10,344,030		$	(6,660,379	)
Investing activities		(2,192,094	)		(613,725	)		(1,578,369	)
Financing activities		(1,477,781	)		(8,830,529	)		7,352,748
Increase (decrease) in cash and cash equivalents	$	13,776		$	899,776		$	(886,000	)

Operating activities:

Net cash provided by operating activities decreased $6,660,379 during the 2017 period, as compared to the 2016 period, primarily the result of the following:

• Receipts of oil, NGL and natural gas sales (net of production taxes and gathering, transportation and marketing costs) and other decreased $1,589,989.

• Decreased receipts from leasing of fee mineral acreage of $1,846,234.

• Decreased net receipts on derivative contracts of $3,723,984.

• Decreased interest payments of $84,598.

• Decreased payments for G&A and other expenses of $121,773.

• Decreased payments for field operating expenses of $303,070.

Investing activities:

Net cash used by investing activities increased $1,578,369 during the 2017 period, as compared to the 2016 period, primarily due to:

• Higher payments for drilling and completion activity during 2017 increased capital expenditures by $888,409.

• Decreased proceeds from sales of assets of $627,547.

Financing activities:

Net cash used by financing activities decreased $7,352,748 during the 2017 period, as compared to the 2016 period, primarily the result of the following:

• During the period ended December 31, 2016, net payments on long term debt were $400,000; during the period ended December 31, 2015, net payments on long term debt were $8,000,000.

Capital Resources:

Capital expenditures to drill and complete wells increased $888,409 (69%) from the 2016 to the 2017 period. The Company has recently agreed to participate in eight BP operated southeastern Oklahoma Woodford wells with an average working interest of 20% and an average net revenue interest of 27.4%. Six wells have been drilled and the last two wells are drilling. Four of those wells are currently being completed and are expected to begin producing in the next 30 days. The remaining four wells are projected to be completed and start producing early in the third quarter of 2017. The Company has agreed to participate in six Anadarko Basin Woodford wells, operated by Cimarex Energy, with 17.5% working interest and 16.25% net revenue interest. Two wells have been drilled, two additional wells are drilling and the remaining two wells are scheduled to be drilled sequentially by the two drilling rigs

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currently on the property. Cimarex plans to drill all six wells before beginning completion operations. These six wells are expected to be completed and start producing in the third quarter of 2017. The Company is also planning to participate in a continuous ten-well drilling program utilizing one rig on our Eagle Ford Shale leasehold. The first well in this program is drilling. The first two wells are projected to be completed and start producing in April 2017. The next four wells are expected to be completed and start producing in the fourth quarter of 2017 and the remaining four wells should begin producing in the first quarter of 2018.

Activity from these three plays is expected to significantly increase our capital expenditures in 2017 compared to 2016. Capital expenditures on these wells in 2017 are expected to be partially funded by utilization of the Company’s credit facility.

Since the Company is not the operator of any of its oil and natural gas properties, it is extremely difficult for us to predict levels of future participation in the drilling and completion of new wells and their associated capital expenditures. This makes capital expenditures for drilling and completion projects difficult to forecast.

Even though oil, NGL and natural gas production volumes decreased 20% on an Mcfe basis during the 2017 period, as compared to the 2016 period, the Company anticipates that oil, NGL and natural gas daily volumes will increase materially later in 2017 as new wells being drilled in the southeastern Oklahoma Woodford, Anadarko Basin Woodford (CANA) and Eagle Ford Shale begin to produce throughout the remainder of 2017.

The Company received lease bonus payments during the first quarter of 2017 totaling approximately $0.8 million. The Company has also received lease bonus payments of $1.1 million thus far during the 2017 second quarter. 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 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 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:

	Three months ended
	December 31, 2016
Cash provided by operating activities	$	3,683,651
Cash provided (used) by:
Capital expenditures - drilling and completion of wells		(2,174,523	)
Quarterly dividends of $.04 per share		(670,104	)
Treasury stock purchases		(407,677	)
Net borrowings (payments) on credit facility		(400,000	)
Other investing and financing activities		(17,571	)
Net cash used		(3,669,875	)
Net increase (decrease) in cash	$	13,776

Outstanding borrowings on the credit facility at December 31, 2016, were $44,100,000.

Looking forward, the Company expects to fund overhead costs, capital additions related to the drilling and completion of wells, treasury stock purchases, if any, and dividend payments primarily from cash provided by operating activities, cash on hand and borrowings utilizing our bank credit facility. Any excess cash is intended to be used to reduce existing bank debt. The Company had availability ($35,900,000 at December 31, 2016) under its revolving credit facility and is in compliance with its debt covenants (current ratio, debt to trailing 12-month EBITDA, as defined, and dividends as a percent of operating cash flow). Non-cash expenses (such as impairment) are excluded from the EBITDA calculation. The debt covenants require a maximum ratio of the Company’s debt to EBITDA of 4:1. As of December 31, 2016, the debt to EBITDA ratio was 2.28:1.

The borrowing base under the credit facility was redetermined in December 2016 and left unchanged at $80 million, which is a level that is expected to provide ample liquidity for the Company to continue to employ its normal operating strategies.

(15)

Based on expected capital expenditure levels, anticipated cash provided by operating activities for 2017 and availability under its credit facility, the Company has sufficient liquidity to fund its ongoing operations.

RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2016 – COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2015

Overview:

The Company recorded a first quarter 2017 net loss of $2,238,392, or $0.13 per share, as compared to net loss of $2,799,118, or $0.17 per share, in the 2016 quarter. The decrease in net loss was principally the result of decreased DD&A, provision for impairment and LOE; partially offset by increased losses on derivative contracts, decreases in lease bonuses and rentals and decreased benefit from income taxes.These items are further discussed below.

Oil, NGL and Natural Gas Sales:

Oil, NGL and natural gas sales decreased $156,070 or 2% for the 2017 quarter. Oil, NGL and natural gas sales were down due to decreases in oil, NGL and natural gas sales volumes of 29%, 26% and 17%, respectively, somewhat offset by increases in oil, NGL and natural gas prices of 17%, 46% and 34%, 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 2017 and 2016:

	Oil Bbls		Average		Mcf		Average		NGL Bbls		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Three months ended
12/31/2016		75,636	$	46.09		1,849,692	$	2.57		35,651	$	18.65		2,517,414	$	3.54
12/31/2015		106,362	$	39.34		2,216,922	$	1.92		48,051	$	12.78		3,143,400	$	2.88

The oil production decrease is principally the result of production decline from the Eagle Ford Shale in South Texas. To a lesser extent, declining production from the Anadarko Basin Granite Wash, Marmaton and Cleveland in western Oklahoma and the Texas Panhandle also contributed to the reduction. The reduction in natural gas production was largely the result of declining production from the Fayetteville Shale in Arkansas, the Woodford Shale in southeastern Oklahoma and the Anadarko Basin Granite Wash in Oklahoma. The decrease was partially offset by production from new wells in the Anadarko Woodford Shale and the STACK Play, both in Oklahoma. The NGL production decrease primarily resulted from declining production in the Anadarko Basin Woodford Shale, Anadarko Basin Granite Wash and the Marietta Basin Woodford Shale, all in Oklahoma. To a lesser extent, declining production from the Eagle Ford Shale in South Texas also contributed to the reduction.

Production for the last five quarters was as follows:

Quarter ended	Oil Bbls Sold		Mcf Sold		NGL Bbls Sold		Mcfe Sold
12/31/2016		75,636		1,849,692		35,651		2,517,414
9/30/2016		78,398		1,940,749		44,598		2,678,725
6/30/2016		88,732		2,112,567		40,477		2,887,821
3/31/2016		90,760		2,014,139		37,934		2,786,303
12/31/2015		106,362		2,216,922		48,051		3,143,400

Lease Bonuses and Rentals:

Lease bonuses and rentals decreased $1,587,546 in the 2017 quarter. The decrease was mainly due to the Company leasing 4,057 net mineral acres in Cochran County, Texas, and 972 net mineral acres in Woodward County, Oklahoma, in the 2016 quarter. The company leased 386 net mineral acres in Canadian, Grady and McClain counties in Oklahoma in the 2017 quarter.

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was a net liability of $2,944,534 as of December 31, 2016, and a net asset of $636,114 as of December 31, 2015. We had a net loss on derivative contracts of $2,700,533 in the 2017 quarter as compared to a net loss of $34,936 in the 2016 quarter. The change is principally due to the oil and natural gas collars and fixed price swaps being more punitive in the 2017 quarter, as NYMEX oil and natural gas futures experienced more of an increase in price in relation to the collars and the fixed prices of the swaps.

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Lease Operating Expenses (LOE):

LOE decreased $517,121 or 14% in the 2017 quarter. LOE per Mcfe increased in the 2017 quarter to $1.21 compared to $1.13 in the 2016 quarter. LOE related to field operating costs decreased $563,230 in the 2017 quarter compared to the 2016 quarter, a 25% decrease. Field operating costs were $.67 per Mcfe in the 2017 quarter as compared to $.72 per Mcfe in the 2016 quarter. The decrease in rate in the 2017 quarter is principally the result of prior period adjustments received from operators as well as decreased operating costs seen in Eagle Ford and other fields.

The decrease in LOE related to field operating costs was offset by an increase in handling fees (primarily gathering, transportation and marketing costs) of $46,109 in the 2017 quarter compared to the 2016 quarter. On a per Mcfe basis, these fees increased $.13 due mainly to a 29% decrease in oil production versus a 17% decrease in natural gas production. Natural gas sales bear the large majority of the handling fees while oil sales incur a much smaller amount. Handling fees are charged either as a percent of sales or based on production volumes.

Depreciation, Depletion and Amortization (DD&A):

DD&A decreased $2,123,389 or 31% in the 2017 quarter. DD&A in the 2017 quarter was $1.92 per Mcfe as compared to $2.21 per Mcfe in the 2016 quarter. DD&A decreased $737,822 as a result of this $.29 decrease in the DD&A rate per Mcfe. An additional decrease of $1,385,567 was the result of production decreasing 20% in the 2017 quarter compared to the 2016 quarter. The rate decrease is mainly due to impairment expense in the prior year lowering our depreciable basis.

Provision for Impairment:

The provision for impairment decreased $3,733,273 in the 2017 quarter compared to the 2016 quarter. During the 2016 quarter, impairment of $3,733,273 was recorded on twenty-one fields. Three oil and liquids-rich fields accounted for $3,212,968 of the impairment mainly due to continued declining oil and NGL prices. During the 2017 quarter, there was no impairment recorded.

Loss (Gain) on Asset Sales and Other:

Gain on asset sales decreased $271,080 in the 2017 quarter. This decrease is primarily related to the gain on sale of the Company’s only asset in one of its partnership investments in the 2016 quarter. There were no asset sales in the 2017 quarter.

Income Taxes:

Benefit for income taxes decreased in the 2017 quarter by $1,261,000, the result of a $1,821,726 decrease in pre-tax loss in the 2017 quarter, compared to the 2016 quarter, and a decrease in the effective tax rate from 46% in the 2016 quarter to 33% in the 2017 quarter. When a provision for income taxes is expected for the year (as is the case for 2017), 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, as was the case for 2016.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Critical accounting policies are those the Company believes are most important to portraying its financial conditions and results of operations and also require the greatest amount of subjective or complex judgments by management. Judgments and uncertainties regarding the application of these policies may result in materially different amounts being reported under various conditions or using different assumptions. There have been no material changes to the critical accounting policies previously disclosed in the Company’s Form 10-K for the fiscal year ended September 30, 2016.

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 2017 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 2017 derivative contracts, the price sensitivity in 2017 for each $1.00 per barrel change in wellhead oil price is $364,252 for operating revenue based on the

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Company’s prior year oil volumes. The price sensitivity in 2017 for each $0.10 per Mcf change in wellhead natural gas price is $828,438 for operating revenue based on the Company’s prior year natural gas volumes.

Commodity Price Risk

The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas and oil prices. The Company does not enter into these derivatives for speculative or trading purposes. All of our outstanding derivative contracts are with Bank of Oklahoma and are secured. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in oil and natural gas prices. These derivative contracts expose the Company to risk of financial loss and limit the benefit of future increases in prices. For the Company’s oil fixed price swaps, a change of $1.00 in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $7,000. For the Company’s oil collars, a change of $1.00 in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $13,000. For the Company’s natural gas fixed price swaps, a change of $.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $243,000. For the Company’s natural gas collars, a change of $.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $331,000.

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facilities. The revolving loan bears interest at the BOK prime rate plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. At December 31, 2016, the Company had $44,100,000 outstanding under this facility and the effective interest rate was 2.81%. 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 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 December 31, 2016, 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
12/1 - 12/31/16		17,119	$	23.81		17,119	$	594,533
Total		17,119	$	23.81		17,119

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Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan in March 2010, as amended in March 2014, the Board of Directors approved repurchase of up to $1.5 million of the Company’s common stock, from time to time, 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. Pursuant to previously adopted board resolutions, the purchase of an additional $1.5 million of the Company’s common stock became authorized and approved effective June 26, 2013. The shares are held in treasury and are accounted for using the cost method. Effective May 14, 2014, the Board adopted resolutions to allow management to repurchase the Company’s common stock at their discretion.

ITEM 6 EXHIBITS

(a)	EXHIBITS	Exhibit 31.1 and 31.2 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002
		Exhibit 32.1 and 32.2 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002
		Exhibit 101.INS – XBRL Instance Document
		Exhibit 101.SCH – XBRL Taxonomy Extension Schema Document
		Exhibit 101.CAL – XBRL Taxonomy Extension Calculation Linkbase Document
		Exhibit 101.LAB – XBRL Taxonomy Extension Labels Linkbase Document
		Exhibit 101.PRE – XBRL Taxonomy Extension Presentation Linkbase Document
		Exhibit 101.DEF – XBRL Taxonomy Extension Definition Linkbase Document
(b)	Form 8-K	Dated (12/13/16), item 5.02 – Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers
	Form 8-K	Dated (1/13/17), item 5.02 – Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers
	Form 8-K	Dated (1/18/17), item 3.03 – Material Modifications to Rights of Security Holders; Item 5.03 – Amendments to Articles of Incorporation or Bylaws; Change in Fiscal Year

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.
February 6, 2017	/s/ Paul F. Blanchard Jr.
Date	Paul F. Blanchard Jr., President and
	Chief Executive Officer
February 6, 2017	/s/ Robb P. Winfield
Date	Robb P. Winfield, Vice President,
	Chief Financial Officer and Controller

(19)

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: February 6, 2017

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: February 6, 2017

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 December 31, 2016, 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

February 6, 2017

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 December 31, 2016, 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

February 6, 2017

XML

Document and Entity Information - shares	3 Months Ended
	Dec. 31, 2016	Feb. 06, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	PANHANDLE OIL & GAS INC
Entity Central Index Key	0000315131
Document Type	10-Q
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--09-30
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		16,640,048

XML

Condensed Balance Sheets - USD ($)		Dec. 31, 2016	Sep. 30, 2016
Current assets:
Cash and cash equivalents		$ 484,989	$ 471,213
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)		5,526,787	5,287,229
Refundable income taxes		98,040	83,874
Other		273,397	419,037
Total current assets		6,383,213	6,261,353
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		437,851,114	434,469,093
Non-producing oil and natural gas properties		7,538,806	7,574,649
Other		1,068,778	1,069,658
Gross properties and equipment, at cost, based on successful efforts accounting		446,458,698	443,113,400
Less accumulated depreciation, depletion and amortization		(256,491,564)	(251,707,749)
Net properties and equipment		189,967,134	191,405,651
Investments		172,352	157,322
Total assets		196,522,699	197,824,326
Current liabilities:
Accounts payable		3,457,200	2,351,623
Derivative contracts, net	[1]	2,933,947	403,612
Accrued liabilities and other		1,968,967	1,718,558
Total current liabilities		8,360,114	4,473,793
Long-term debt		44,100,000	44,500,000
Deferred income taxes, net		29,569,007	30,676,007
Asset retirement obligations		2,990,823	2,958,048
Derivative contracts, net	[1]	10,587	24,659
Stockholders' equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 16,863,004 issued at December 31, 2016, and September 30, 2016		280,938	280,938
Capital in excess of par value		2,476,066	3,191,056
Deferred directors' compensation		3,509,031	3,403,213
Retained earnings		108,903,533	112,482,284
Stockholders' Equity		115,169,568	119,357,491
Less treasury stock, at cost; 223,661 shares at December 31, 2016, and 262,708 shares at September 30, 2016		(3,677,400)	(4,165,672)
Total stockholders' equity		111,492,168	115,191,819
Total liabilities and stockholders' equity		$ 196,522,699	$ 197,824,326

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

XML

Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Sep. 30, 2016
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	16,863,004	16,863,004
Treasury stock, shares	223,661	262,708

XML

Condensed Statements Of Operations - USD ($)	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Oil, NGL and natural gas sales	$ 8,899,218	$ 9,055,288
Lease bonuses and rentals	837,958	2,425,504
Gains (losses) on derivative contracts	(2,700,533)	(34,936)
Income (loss) from partnerships	15,030	16,269
Total revenues	7,051,673	11,462,125
Costs and expenses:
Lease operating expenses	3,049,415	3,566,536
Production taxes	367,845	321,841
Exploration costs	(2,243)	27,790
Depreciation, depletion and amortization	4,834,263	6,957,652
Provision for impairment	0	3,733,273
Loss (gain) on asset sales and other	12,934	(269,706)
Interest expense	292,369	360,562
General and administrative	1,842,482	1,912,079
Bad debt expense (recovery)		19,216
Total costs and expenses	10,397,065	16,629,243
Income (loss) before provision (benefit) for income taxes	(3,345,392)	(5,167,118)
Provision (benefit) for income taxes	(1,107,000)	(2,368,000)
Net income (loss)	$ (2,238,392)	$ (2,799,118)
Basic and diluted earnings (loss) per common share (Note 3)	$ (0.13)	$ (0.17)
Basic and diluted weighted average shares outstanding:
Common shares	16,604,149	16,563,942
Unissued, directors' deferred compensation shares	274,035	255,060
Basic and diluted weighted average shares outstanding	16,878,184	16,819,002
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

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, shares at Sep. 30, 2015		16,863,004
Balances, Treasury shares at Sep. 30, 2015						(302,623)
Balances at Sep. 30, 2015	$ 127,004,675	$ 280,938	$ 2,993,119	$ 3,084,289	$ 125,446,473	$ (4,800,144)
Purchase of treasury stock	(117,165)					$ (117,165)
Purchase of treasury stock, shares						(7,477)
Restricted stock awards	371,407		371,407
Net income (loss)	(2,799,118)				(2,799,118)
Dividends ($.08 per share)	(1,337,982)				(1,337,982)
Distribution of restricted stock to officers and directors	(44,766)		(449,307)			$ 404,541
Distribution of restricted stock to officers and directors, shares						25,507
Increase in deferred directors' compensation charged to expense	85,930			85,930
Balances, shares at Dec. 31, 2015		16,863,004
Balances, Treasury shares at Dec. 31, 2015						(284,593)
Balances at Dec. 31, 2015	$ 123,162,981	$ 280,938	2,915,219	3,170,219	121,309,373	$ (4,512,768)
Balances, shares at Sep. 30, 2016		16,863,004
Balances, Treasury shares at Sep. 30, 2016	(262,708)					(262,708)
Balances at Sep. 30, 2016	$ 115,191,819	$ 280,938	3,191,056	3,403,213	112,482,284	$ (4,165,672)
Purchase of treasury stock	(407,677)					$ (407,677)
Purchase of treasury stock, shares						(17,119)
Restricted stock awards	180,412		180,412
Net income (loss)	(2,238,392)				(2,238,392)
Dividends ($.08 per share)	(1,340,359)				(1,340,359)
Distribution of restricted stock to officers and directors	547		(895,402)			$ 895,949
Distribution of restricted stock to officers and directors, shares						56,166
Increase in deferred directors' compensation charged to expense	$ 105,818			105,818
Balances, shares at Dec. 31, 2016		16,863,004
Balances, Treasury shares at Dec. 31, 2016	(223,661)					(223,661)
Balances at Dec. 31, 2016	$ 111,492,168	$ 280,938	$ 2,476,066	$ 3,509,031	$ 108,903,533	$ (3,677,400)

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Statements Of Stockholders' Equity (Parenthetical) - $ / shares	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Statement Of Stockholders Equity [Abstract]
Dividends per share	$ 0.08	$ 0.08

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Condensed Statements Of Cash Flows - USD ($)	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Operating Activities
Net income (loss)	$ (2,238,392)	$ (2,799,118)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	4,834,263	6,957,652
Impairment	0	3,733,273
Provision for deferred income taxes	(1,107,000)	(3,747,000)
Exploration costs	(2,243)	27,790
Gain from leasing fee mineral acreage	(837,732)	(2,425,131)
Proceeds from leasing fee mineral acreage	847,578	2,693,812
Net (gain) loss on sales of assets		(271,080)
Amortization of partnerships	2,541	19,984
Directors' deferred compensation expense	105,818	85,930
Restricted stock awards	180,412	371,407
Bad debt expense (recovery)		19,216
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables	(239,558)	2,335,449
Fair value of derivative contracts	2,516,263	3,574,650
Refundable production taxes		1,162
Other current assets	145,640	(659,324)
Accounts payable	(90,474)	(484,882)
Income taxes receivable	(14,166)	345,897
Income taxes payable		1,073,551
Accrued liabilities	(419,299)	(509,208)
Total adjustments	5,922,043	13,143,148
Net cash provided by operating activities	3,683,651	10,344,030
Investing Activities
Capital expenditures, including dry hole costs	(2,174,523)	(1,286,114)
Investments in partnerships	(17,571)	44,842
Proceeds from sales of assets		627,547
Net cash provided (used) by investing activities	(2,192,094)	(613,725)
Financing Activities
Borrowings under debt agreement	4,436,304	2,958,515
Payments of loan principal	(4,836,304)	(10,958,515)
Purchases of treasury stock	(407,677)	(117,165)
Payments of dividends	(670,104)	(668,364)
Excess tax benefit on stock-based compensation		(45,000)
Net cash provided (used) by financing activities	(1,477,781)	(8,830,529)
Increase (decrease) in cash and cash equivalents	13,776	899,776
Cash and cash equivalents at beginning of period	471,213	603,915
Cash and cash equivalents at end of period	484,989	1,503,691
Supplemental Schedule of Noncash Investing and Financing Activities:
Dividends declared and unpaid	670,255	669,618
Additions to asset retirement obligations	594	4,524
Gross additions to properties and equipment	3,370,574	3,455,245
Net (increase) decrease in accounts payable for properties and equipment additions	(1,196,051)	(2,169,131)
Capital expenditures and acquisitions, including dry hole costs	$ 2,174,523	$ 1,286,114

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Basis of Presentation and Accounting Principles

3 Months Ended

Dec. 31, 2016

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 2016 Annual Report on Form 10-K.

Adoption of New Accounting Pronouncements

In April 2015, the FASB issued Accounting Standards Update (“ASU”) 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The update requires that debt issuance costs related to a recognized debt liability, such as senior notes, term loans and note payables, be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with the presentation of debt discounts. Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset. The recognition and measurement guidance for debt issuance costs is not affected by the update. For public entities, the guidance is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years.

In August 2015, the FASB issued ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, which allows for line-of-credit arrangements to be handled consistently with the presentation of debt issuance costs prior to ASU 2015-03 issued in April 2015. For public entities, the guidance is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years.

The Company adopted ASU 2015-03 and ASU 2015-15 as of December 31, 2016. The Company elected to continue to show debt issuance costs associated with its credit facility (Company’s only debt) as assets versus a direct reduction of the debt liability. Therefore, the adoption had no impact on the Company's current and previously reported balance sheets, shareholders' equity, results of operations, or cash flows. In accordance with ASU 2015-15, unamortized debt issuance costs associated with the Company's credit facility, which amounted to $232,928 and $263,584 as of December 31, 2016, and September 30, 2016, respectively, remain reflected in "Other property and equipment" on the balance sheets.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. The update requires that deferred income tax assets and liabilities be classified as noncurrent in the balance sheet. For public entities, the guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years.

The Company early adopted ASU 2015-17 as of December 31, 2016, on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $201,900 and $310,900 as of December 31, 2016, and September 30, 2016, respectively, from "Deferred income taxes" in current assets to “Deferred income tax, net” in long term liabilities on the balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2015-17.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which addresses certain issues where diversity in practice was identified and may change how an entity classifies certain cash receipts and cash payments on its statement of cash flows. The new guidance also clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. This guidance will generally be applied retrospectively and is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption is permitted. All of the amendments in ASU 2016-15 are required to be adopted at the same time.

The Company early adopted ASU 2016-15 as of December 31, 2016. As a result of the adoption, the Company reclassified “Proceeds from leasing fee mineral acreage”, which totaled $847,578 and $2,693,812 as of December 31, 2016, and December 31, 2015, respectively, from Investing Activities to Operating Activities on the Condensed Statements of Cash Flows as these transactions are made in our normal course of business and represent operating activities based on the application of the predominance principle. As another result of this adoption, we are also electing to classify our distributions received from equity method investments using the Cumulative Earnings Approach. Distributions received are considered returns on investment and classified as cash inflows from operating activities, unless the investor’s cumulative distributions received less distributions received in prior periods that were determined to be returns of investment exceed cumulative equity in earnings recognized by the investor. When such an excess occurs, the current-period distribution up to this excess should be considered a return of investment and classified as cash inflows from investing activities. This election did not have any impact on our cash flow statements as the Company was already applying this approach. Adoption of ASU 2016-15 had no impact on the Company's current and previously reported shareholders' equity, results of operations or balance sheets. The affected prior period balances in the Condensed Statements of Cash Flows presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2016-15.

In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The new guidance is intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. The guidance changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, and will be adopted either prospectively, retrospectively or using a modified retrospective transition approach depending on the topic covered in the standard. Early adoption is permitted for any organization in any interim or annual period. On a prospective basis companies will no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies will be recognized as income tax expense or benefit in the income statement. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. Also, companies will have to present excess tax benefits and deficiencies as operating activities on the statement of cash flows (prospectively or retrospectively). The new guidance will also require an employer to classify as a financing activity in its statement of cash flows the cash paid to a tax authority when shares are withheld to satisfy the employer’s statutory income tax withholding obligation.

The Company early adopted ASU 2016-09 as of October 1, 2016. As a result of the adoption, the Company recorded $228,000 of excess tax benefits from stock-based compensation in the “Provision (benefit) for income taxes” on the Condensed Statements of Operations in the current period versus “Capital in excess of par” on the Condensed Balance Sheets as was previously required. This part of the guidance is to be applied prospectively, so the prior period balances have not been reclassified. The Company also presented excess tax benefits from stock-based compensation in the “Operating Activities” section of the Condensed Statements of Cash Flows in the current period versus the “Financing Activities” section of the Condensed Statements of Cash Flows as was previously presented. The Company has elected to apply this part of the guidance prospectively, so the prior period balances have not been reclassified. The guidance also requires that companies present employees taxes paid upon vesting as financing activities on the statement of cash flows. This requirement had no impact on the Company, as this has been the practice historically. The Company is also electing to account for forfeitures of awards as they occur, instead of estimating a forfeiture amount. A cumulative-effect adjustment to retained earnings was not necessary for this transition as there were no material forfeitures estimated or incurred in the past.

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842). Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date: 1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and 2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new lease guidance simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. Lessees will no longer be provided with a source of off-balance sheet financing. For public entities, the guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this update will have on our financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The new guidance is intended to improve the recognition and measurement of financial instruments. The new guidance is effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. We are assessing the potential impact that this update will have on our financial statements.

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

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

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Income Taxes

3 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

NOTE 2: Income Taxes

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

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 are not directly related to the amount of pre-tax income recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the quarter ended December 31, 2016, was 33% as compared to 46% for the quarter ended December 31, 2015.

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Basic And Diluted Earnings (Loss) Per Share

3 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

Basic And Diluted Earnings (Loss) Per Share

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

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

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Long-Term Debt

3 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Long-Term Debt

NOTE 4: Long-term Debt

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a current borrowing base of $80,000,000 and a maturity date of November 30, 2018. 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 with a net book value of $162,622,006 at December 31, 2016. The interest rate is based on BOK prime plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. 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 a larger percent of the borrowing base is advanced. At December 31, 2016, the effective interest rate was 2.81%.

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 (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. In December 2016, the borrowing base was redetermined by the banks and left unchanged at $80,000,000. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of treasury stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined – 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) of no more than 4.0 to 1.0. At December 31, 2016, the Company was in compliance with the covenants of the loan agreement and has $35,900,000 of availability under its outstanding credit facility.

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Deferred Compensation Plan For Non-Employee Directors

3 Months Ended

Dec. 31, 2016

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Deferred Compensation Plan For Non-Employee Directors

NOTE 5: Deferred Compensation Plan for Non-Employee Directors

Annually, non-employee directors may elect to be included in the Deferred Compensation Plan for Non-Employee Directors. The Deferred Compensation Plan for Non-Employee Directors provides that each outside director may individually elect to be credited with future unissued shares of Company common stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees, and may elect to receive shares, when issued, over annual time periods up to ten years. 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 under the Deferred Compensation Plan for Non-Employee Directors be issued to the director. The promise to issue such shares in the future is an unsecured obligation of the Company.

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Restricted Stock Plan

3 Months Ended

Dec. 31, 2016

Restricted Stock Plan [Abstract]

Restricted Stock Plan

NOTE 6: Restricted Stock Plan

In March 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 200,000 shares of common stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. In March 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, as amended, is designed to provide as much flexibility as possible for future grants of restricted stock so that the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate directors and officers of the Company and to align their interests with those of the Company’s shareholders.

Effective in May 2014, the board of directors adopted resolutions to allow management, at their discretion, to purchase the Company’s common stock 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.

On December 9, 2016, the Company awarded 6,845 non-performance based shares and 20,531 performance based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of a three-year period and contains non-forfeitable rights to receive dividends and voting rights during the vesting period. The non-performance and performance based shares had a fair value on their award date of $176,260 and $292,884, respectively. The fair value for the performance and the non-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 9, 2016, through December 9, 2019).

On December 31, 2016, the Company awarded 7,430 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, 2017. The restricted stock contains non-forfeitable rights to receive dividends and voting rights during the vesting period. These non-performance based shares had a fair value on their award date of $174,975.

The following table summarizes the Company’s pre-tax compensation expense for the three months ended December 31, 2016 and 2015, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended
	December 31,
	2016		2015
Performance based, restricted stock	$	79,216	$	269,510
Non-performance based, restricted stock		101,196		101,897
Total compensation expense	$	180,412	$	371,407

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 December 31, 2016
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	421,524		2.37
Non-performance based, restricted stock		454,090		1.87
Total	$	875,614

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

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Oil, NGL And Natural Gas Reserves

3 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Oil, NGL And Natural Gas Reserves

NOTE 7: 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 geological and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing 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.

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Impairment

3 Months Ended

Dec. 31, 2016

Impairment [Abstract]

Impairment

NOTE 8: Impairment

All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as: inflation rates; future 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 the three months ended December 31, 2016 and 2015, the assessment resulted in impairment provisions on producing properties of $0 and $3,733,273, respectively. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company.

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Capitalized Costs

3 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Capitalized Costs

NOTE 9: Capitalized Costs

As of December 31, 2016, and September 30, 2016, non-producing oil and natural gas properties include costs of $0 and $5,917, respectively, on exploratory wells which were drilling and/or testing.

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Derivatives

3 Months Ended

Dec. 31, 2016

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivatives

NOTE 10: Derivatives

The Company has entered into commodity price derivative agreements including fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. These contracts cover only a portion of the Company’s natural gas and oil production and provide only partial price protection against declines in natural gas and oil prices. These derivative instruments may expose the Company to risk of financial loss and limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are secured under its credit facility with Bank of Oklahoma. The derivative instruments have settled or will settle based on the prices below.

Derivative contracts in place as of December 31, 2016

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.65 ceiling
November 2016 - March 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.95 ceiling
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.60 floor / $3.25 ceiling
January - March 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.20 floor / $4.00 ceiling
January - June 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.85 floor / $3.35 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.47 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.65 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.60 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.20 floor / $3.65 ceiling
January - March 2018	100,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $3.95 ceiling
Natural gas fixed price swaps
October 2016 - March 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.200
November 2016 - April 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.955
January - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.665
January - December 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.100
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.070
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.210
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.300
July - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.510
January - March 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.700
Oil costless collars
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$40.00 floor / $58.50 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $54.00 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $55.50 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$50.00 floor / $55.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$52.00 floor / $58.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$53.00 floor / $57.75 ceiling
April - December 2017	2,000 Bbls	NYMEX WTI	$50.00 floor / $57.50 ceiling
July - December 2017	5,000 Bbls	NYMEX WTI	$45.00 floor / $56.25 ceiling
Oil fixed price swaps
January - December 2017	3,000 Bbls	NYMEX WTI	$53.89
April - June 2017	5,000 Bbls	NYMEX WTI	$53.50
April - December 2017	2,000 Bbls	NYMEX WTI	$54.20

Derivative contracts in place as of September 30, 2016

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
April - October 2016	200,000 Mmbtu	NYMEX Henry Hub	$1.95 floor / $2.40 ceiling
October - December 2016	70,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.05 ceiling
October - December 2016	50,000 Mmbtu	NYMEX Henry Hub	$2.90 floor / $3.40 ceiling
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.65 ceiling
November 2016 - March 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.95 ceiling
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.60 floor / $3.25 ceiling
January - June 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.85 floor / $3.35 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.47 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
Natural gas fixed price swaps
October 2016	100,000 Mmbtu	NYMEX Henry Hub	$2.410
October 2016 - March 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.200
November 2016 - April 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.955
January - December 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.100
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.070
Oil costless collars
July - December 2016	3,000 Bbls	NYMEX WTI	$35.00 floor / $49.00 ceiling
October - December 2016	3,000 Bbls	NYMEX WTI	$40.00 floor / $47.25 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$40.00 floor / $58.50 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $54.00 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $55.50 ceiling

The Company has elected not to complete all of the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net liability of $2,944,534 as of December 31, 2016, and a net liability of $428,271 as of September 30, 2016.

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, 2016, and September 30, 2016. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at December 31, 2016, and September 30, 2016.

	December 31, 2016				September 30, 2016
	Fair Value (a)				Fair Value (a)
	Commodity Contracts				Commodity Contracts
	Current Liabilities		Non-Current Liabilities		Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities
Gross amounts recognized	$	2,933,947	$	10,587	$	68,235		$	471,847		$	4,759		$	29,418
Offsetting adjustments		-		-		(68,235	)		(68,235	)		(4,759	)		(4,759	)
Net presentation on Condensed Balance Sheets	$	2,933,947	$	10,587	$	-		$	403,612		$	-		$	24,659

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

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

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Fair Value Measurements

3 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

NOTE 11: 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 December 31, 2016.

	Fair Value Measurement at December 31, 2016
	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	$	-	$	(1,138,750	)	$	-		$	(1,138,750	)
Derivative Contracts - Collars	$	-	$	-		$	(1,805,784	)	$	(1,805,784	)

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

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

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

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

Instrument Type	Unobservable Input	Range	Weighted Average		Fair Value December 31, 2016
Oil Collars	Oil price volatility curve	0% - 27.38%		18.53%	$	(493,394	)
Natural Gas Collars	Gas price volatility curve	0% - 39.17%		21.87%	$	(1,312,390	)

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

	Derivatives
Balance of Level 3 as of October 1, 2016	$	(316,658	)
Total gains or (losses)
Included in earnings		(1,349,636	)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(139,490	)
Transfers in and out of Level 3		-
Balance of Level 3 as of December 31, 2016	$	(1,805,784	)

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

	Quarter Ended December 31,
	2016				2015
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	3,152,454	$	3,733,273

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

At December 31, 2016, and September 30, 2016, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which the valuation is classified as Level 3 and is based on a valuation technique that requires inputs that are both unobservable and significant to the overall fair value measurement. The fair value measurement of our long-term debt is valued using a discounted cash flow model that calculates the present value of future cash flows pursuant to the terms of the debt agreements and applies estimated current market interest rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

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Basis of Presentation and Accounting Principles (Policies)

3 Months Ended

Dec. 31, 2016

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 2016 Annual Report on Form 10-K.

Adoption Of New Accounting Pronouncements

Adoption of New Accounting Pronouncements

In April 2015, the FASB issued Accounting Standards Update (“ASU”) 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The update requires that debt issuance costs related to a recognized debt liability, such as senior notes, term loans and note payables, be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with the presentation of debt discounts. Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset. The recognition and measurement guidance for debt issuance costs is not affected by the update. For public entities, the guidance is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years.

In August 2015, the FASB issued ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, which allows for line-of-credit arrangements to be handled consistently with the presentation of debt issuance costs prior to ASU 2015-03 issued in April 2015. For public entities, the guidance is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years.

The Company adopted ASU 2015-03 and ASU 2015-15 as of December 31, 2016. The Company elected to continue to show debt issuance costs associated with its credit facility (Company’s only debt) as assets versus a direct reduction of the debt liability. Therefore, the adoption had no impact on the Company's current and previously reported balance sheets, shareholders' equity, results of operations, or cash flows. In accordance with ASU 2015-15, unamortized debt issuance costs associated with the Company's credit facility, which amounted to $232,928 and $263,584 as of December 31, 2016, and September 30, 2016, respectively, remain reflected in "Other property and equipment" on the balance sheets.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. The update requires that deferred income tax assets and liabilities be classified as noncurrent in the balance sheet. For public entities, the guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years.

The Company early adopted ASU 2015-17 as of December 31, 2016, on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $201,900 and $310,900 as of December 31, 2016, and September 30, 2016, respectively, from "Deferred income taxes" in current assets to “Deferred income tax, net” in long term liabilities on the balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2015-17.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which addresses certain issues where diversity in practice was identified and may change how an entity classifies certain cash receipts and cash payments on its statement of cash flows. The new guidance also clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. This guidance will generally be applied retrospectively and is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption is permitted. All of the amendments in ASU 2016-15 are required to be adopted at the same time.

The Company early adopted ASU 2016-15 as of December 31, 2016. As a result of the adoption, the Company reclassified “Proceeds from leasing fee mineral acreage”, which totaled $847,578 and $2,693,812 as of December 31, 2016, and December 31, 2015, respectively, from Investing Activities to Operating Activities on the Condensed Statements of Cash Flows as these transactions are made in our normal course of business and represent operating activities based on the application of the predominance principle. As another result of this adoption, we are also electing to classify our distributions received from equity method investments using the Cumulative Earnings Approach. Distributions received are considered returns on investment and classified as cash inflows from operating activities, unless the investor’s cumulative distributions received less distributions received in prior periods that were determined to be returns of investment exceed cumulative equity in earnings recognized by the investor. When such an excess occurs, the current-period distribution up to this excess should be considered a return of investment and classified as cash inflows from investing activities. This election did not have any impact on our cash flow statements as the Company was already applying this approach. Adoption of ASU 2016-15 had no impact on the Company's current and previously reported shareholders' equity, results of operations or balance sheets. The affected prior period balances in the Condensed Statements of Cash Flows presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2016-15.

In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The new guidance is intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. The guidance changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, and will be adopted either prospectively, retrospectively or using a modified retrospective transition approach depending on the topic covered in the standard. Early adoption is permitted for any organization in any interim or annual period. On a prospective basis companies will no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies will be recognized as income tax expense or benefit in the income statement. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. Also, companies will have to present excess tax benefits and deficiencies as operating activities on the statement of cash flows (prospectively or retrospectively). The new guidance will also require an employer to classify as a financing activity in its statement of cash flows the cash paid to a tax authority when shares are withheld to satisfy the employer’s statutory income tax withholding obligation.

The Company early adopted ASU 2016-09 as of October 1, 2016. As a result of the adoption, the Company recorded $228,000 of excess tax benefits from stock-based compensation in the “Provision (benefit) for income taxes” on the Condensed Statements of Operations in the current period versus “Capital in excess of par” on the Condensed Balance Sheets as was previously required. This part of the guidance is to be applied prospectively, so the prior period balances have not been reclassified. The Company also presented excess tax benefits from stock-based compensation in the “Operating Activities” section of the Condensed Statements of Cash Flows in the current period versus the “Financing Activities” section of the Condensed Statements of Cash Flows as was previously presented. The Company has elected to apply this part of the guidance prospectively, so the prior period balances have not been reclassified. The guidance also requires that companies present employees taxes paid upon vesting as financing activities on the statement of cash flows. This requirement had no impact on the Company, as this has been the practice historically. The Company is also electing to account for forfeitures of awards as they occur, instead of estimating a forfeiture amount. A cumulative-effect adjustment to retained earnings was not necessary for this transition as there were no material forfeitures estimated or incurred in the past.

New Accounting Pronouncements Yet To Be Adopted

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842). Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date: 1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and 2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new lease guidance simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. Lessees will no longer be provided with a source of off-balance sheet financing. For public entities, the guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this update will have on our financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The new guidance is intended to improve the recognition and measurement of financial instruments. The new guidance is effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. We are assessing the potential impact that this update will have on our financial statements.

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

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

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Restricted Stock Plan (Tables)

3 Months Ended

Dec. 31, 2016

Restricted Stock Plan [Abstract]

Summary Of Pre-Tax Compensation Expense

The following table summarizes the Company’s pre-tax compensation expense for the three months ended December 31, 2016 and 2015, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended
	December 31,
	2016		2015
Performance based, restricted stock	$	79,216	$	269,510
Non-performance based, restricted stock		101,196		101,897
Total compensation expense	$	180,412	$	371,407

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 December 31, 2016
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	421,524		2.37
Non-performance based, restricted stock		454,090		1.87
Total	$	875,614

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Derivatives (Tables)

3 Months Ended

Dec. 31, 2016

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Summary Of Derivative Instruments Contracts

Derivative contracts in place as of December 31, 2016

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.65 ceiling
November 2016 - March 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.95 ceiling
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.60 floor / $3.25 ceiling
January - March 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.20 floor / $4.00 ceiling
January - June 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.85 floor / $3.35 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.47 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.65 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.60 ceiling
May - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.20 floor / $3.65 ceiling
January - March 2018	100,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $3.95 ceiling
Natural gas fixed price swaps
October 2016 - March 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.200
November 2016 - April 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.955
January - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.665
January - December 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.100
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.070
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.210
April - December 2017	30,000 Mmbtu	NYMEX Henry Hub	$3.300
July - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.510
January - March 2018	50,000 Mmbtu	NYMEX Henry Hub	$3.700
Oil costless collars
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$40.00 floor / $58.50 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $54.00 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $55.50 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$50.00 floor / $55.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$52.00 floor / $58.00 ceiling
January - December 2017	3,000 Bbls	NYMEX WTI	$53.00 floor / $57.75 ceiling
April - December 2017	2,000 Bbls	NYMEX WTI	$50.00 floor / $57.50 ceiling
July - December 2017	5,000 Bbls	NYMEX WTI	$45.00 floor / $56.25 ceiling
Oil fixed price swaps
January - December 2017	3,000 Bbls	NYMEX WTI	$53.89
April - June 2017	5,000 Bbls	NYMEX WTI	$53.50
April - December 2017	2,000 Bbls	NYMEX WTI	$54.20

Derivative contracts in place as of September 30, 2016

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
April - October 2016	200,000 Mmbtu	NYMEX Henry Hub	$1.95 floor / $2.40 ceiling
October - December 2016	70,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.05 ceiling
October - December 2016	50,000 Mmbtu	NYMEX Henry Hub	$2.90 floor / $3.40 ceiling
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.65 ceiling
November 2016 - March 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.95 ceiling
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.60 floor / $3.25 ceiling
January - June 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.85 floor / $3.35 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.47 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
Natural gas fixed price swaps
October 2016	100,000 Mmbtu	NYMEX Henry Hub	$2.410
October 2016 - March 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.200
November 2016 - April 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.955
January - December 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.100
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.070
Oil costless collars
July - December 2016	3,000 Bbls	NYMEX WTI	$35.00 floor / $49.00 ceiling
October - December 2016	3,000 Bbls	NYMEX WTI	$40.00 floor / $47.25 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$40.00 floor / $58.50 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $54.00 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $55.50 ceiling

Summary Of Derivative Contracts

	December 31, 2016				September 30, 2016
	Fair Value (a)				Fair Value (a)
	Commodity Contracts				Commodity Contracts
	Current Liabilities		Non-Current Liabilities		Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities
Gross amounts recognized	$	2,933,947	$	10,587	$	68,235		$	471,847		$	4,759		$	29,418
Offsetting adjustments		-		-		(68,235	)		(68,235	)		(4,759	)		(4,759	)
Net presentation on Condensed Balance Sheets	$	2,933,947	$	10,587	$	-		$	403,612		$	-		$	24,659

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

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Fair Value Measurements (Tables)

3 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

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

	Fair Value Measurement at December 31, 2016
	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	$	-	$	(1,138,750	)	$	-		$	(1,138,750	)
Derivative Contracts - Collars	$	-	$	-		$	(1,805,784	)	$	(1,805,784	)

Summary Of Unobservable Inputs For Level 3 Fair Value Measurements

Instrument Type	Unobservable Input	Range	Weighted Average		Fair Value December 31, 2016
Oil Collars	Oil price volatility curve	0% - 27.38%		18.53%	$	(493,394	)
Natural Gas Collars	Gas price volatility curve	0% - 39.17%		21.87%	$	(1,312,390	)

Summary Of Reconciliation Of Derivative Contracts Classified As Level 3 Measurements

	Derivatives
Balance of Level 3 as of October 1, 2016	$	(316,658	)
Total gains or (losses)
Included in earnings		(1,349,636	)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(139,490	)
Transfers in and out of Level 3		-
Balance of Level 3 as of December 31, 2016	$	(1,805,784	)

Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3

	Quarter Ended December 31,
	2016				2015
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	3,152,454	$	3,733,273

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

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Basis of Presentation and Accounting Principles (Narrative) (Details) - USD ($)				3 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Basis Of Presentation And Accounting Principles [Line Items]
Provision (benefit) for income taxes				$ (1,107,000)	$ (2,368,000)
ASU 2015-17 [Member]
Basis Of Presentation And Accounting Principles [Line Items]
Prior period reclassification	$ 201,900	$ 310,900
ASU 2016-15 [Member]
Basis Of Presentation And Accounting Principles [Line Items]
Prior period reclassification	847,578		$ 2,693,812
ASU 2016-09 [Member]
Basis Of Presentation And Accounting Principles [Line Items]
Provision (benefit) for income taxes				228,000
Other Property and Equipment [Member]
Basis Of Presentation And Accounting Principles [Line Items]
Unamortized debt issuance expense	$ 232,928	$ 263,584		$ 232,928

XML

Income Taxes (Details)	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Effective tax rate	33.00%	46.00%

XML

Long-Term Debt (Details) - Revolving Credit Facility [Member]	3 Months Ended
	Dec. 31, 2016 USD ($)
Line Of Credit Facility [Line Items]
Revolving loan credit facility	$ 200,000,000
Borrowing base of credit facility	$ 80,000,000
Credit facility maturity	Nov. 30, 2018
Properties net book value	$ 162,622,006
Effective Interest rate	2.81%
Funded debt to EBITDA ratio	400.00%
Availability under outstanding credit facility	$ 35,900,000
Minimum [Member]
Line Of Credit Facility [Line Items]
Current ratio	100.00%
Minimum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	0.375%
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	1.875%
Maximum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	1.125%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	2.625%

XML

Deferred Compensation Plan For Non-Employee Directors (Details)	3 Months Ended
	Dec. 31, 2016
Maximum [Member]
Deferred Compensation Plan For Directors [Line Items]
Period outside directors may elect to receive shares	10 years

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Restricted Stock Plan (Narrative) (Details) - USD ($)		3 Months Ended
	Dec. 09, 2016	Dec. 31, 2016	Mar. 31, 2014	Mar. 31, 2010
Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock vesting period		3 years
Non Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock vesting period		1 year
Non Performance Based Restricted Stock [Member] | Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded	6,845
Fair value of shares awarded	$ 176,260
Non Performance Based Restricted Stock [Member] | Non Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded		7,430
Fair value of shares awarded		$ 174,975
Performance Based Restricted Stock [Member] | Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded	20,531
Fair value of shares awarded	$ 292,884
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
	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 180,412	$ 371,407
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	79,216	269,510
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 101,196	$ 101,897

XML

Restricted Stock Plan (Summary Of Unrecognized Compensation Cost) (Details)	3 Months Ended
	Dec. 31, 2016 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 875,614
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 421,524
Weighted Average Period (in years)	2 years 4 months 13 days
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 454,090
Weighted Average Period (in years)	1 year 10 months 13 days

XML

Oil, NGL And Natural Gas Reserves (Details)	3 Months Ended
	Dec. 31, 2016
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Computation of Oil, Natural Gas and NGL Reserves	12 months

XML

Impairment (Details) - USD ($)	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Impairment [Abstract]
Impairment	$ 0	$ 3,733,273

XML

Capitalized Costs (Details) - USD ($)	Dec. 31, 2016	Sep. 30, 2016
Extractive Industries [Abstract]
Cost of Non-Producing Oil and Natural Gas Properties	$ 0	$ 5,917

XML

Derivatives (Summary Of Derivative Instruments Contracts) (Details)	Dec. 31, 2016 MMBTU $ / MMBTU $ / bbl bbl	Sep. 30, 2016 MMBTU $ / MMBTU $ / bbl bbl
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	200,000
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.25	1.95
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.65	2.40
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	80,000	70,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.25	2.75
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.95	3.05
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.60	2.90
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.25	3.40
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	30,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	3.20	2.25
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	4.00	3.65
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	80,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.85	2.25
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.35	3.95
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.80	2.60
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.47	3.25
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	3.00	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.35	3.35
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.80	2.80
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.35	3.47
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.75	3.00
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.35	3.35
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	30,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	3.00	2.80
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.65	3.35
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	3.00	2.75
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.60	3.35
Natural Gas Costless Collars [Member] | Derivative Contract Period Twelve [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	3.20
Natural Gas Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.65
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	3.50
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.95
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Twelve [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		100,000
Contract price		2.410
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Thirteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		25,000
Contract price		3.200
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fourteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	25,000	80,000
Contract price	3.200	2.955
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	80,000	25,000
Contract price	2.955	3.100
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Contract price	3.665	3.070
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Seventeen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	25,000
Contract price	3.100
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Eighteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000
Contract price	3.070
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Nineteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000
Contract price	3.210
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Twenty [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	30,000
Contract price	3.300
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Twenty One [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000
Contract price	3.510
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Twenty Two [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000
Contract price	3.700
Oil Costless Collars [Member] | Derivative Contract Period Seventeen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		3,000
Oil Costless Collars [Member] | Derivative Contract Period Seventeen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl		35.00
Oil Costless Collars [Member] | Derivative Contract Period Seventeen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl		49.00
Oil Costless Collars [Member] | Derivative Contract Period Eighteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		3,000
Oil Costless Collars [Member] | Derivative Contract Period Eighteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl		40.00
Oil Costless Collars [Member] | Derivative Contract Period Eighteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl		47.25
Oil Costless Collars [Member] | Derivative Contract Period Nineteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		3,000
Oil Costless Collars [Member] | Derivative Contract Period Nineteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl		40.00
Oil Costless Collars [Member] | Derivative Contract Period Nineteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl		58.50
Oil Costless Collars [Member] | Derivative Contract Period Twenty [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl		45.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl		54.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty One [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl		45.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl		55.50
Oil Costless Collars [Member] | Derivative Contract Period Twenty Three [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	40.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	58.50
Oil Costless Collars [Member] | Derivative Contract Period Twenty Four [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Four [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Four [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	54.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Five [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Five [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Five [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	55.50
Oil Costless Collars [Member] | Derivative Contract Period Twenty Six [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Six [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	50.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Six [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	55.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Seven [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Seven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	52.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Seven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	58.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Eight [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Eight [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	53.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Eight [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	57.75
Oil Costless Collars [Member] | Derivative Contract Period Twenty Nine [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	50.00
Oil Costless Collars [Member] | Derivative Contract Period Twenty Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	57.50
Oil Costless Collars [Member] | Derivative Contract Period Thirty [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	5,000
Oil Costless Collars [Member] | Derivative Contract Period Thirty [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45.00
Oil Costless Collars [Member] | Derivative Contract Period Thirty [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	56.25
Oil Fixed Price Swaps [Member] | Derivative Contract Period Thirty One [Member]
Derivative [Line Items]
Contract price | $ / bbl	53.89
Production volume covered per month - Oil | bbl	3,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Thirty Two [Member]
Derivative [Line Items]
Contract price | $ / bbl	53.50
Production volume covered per month - Oil | bbl	5,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Thirty Three [Member]
Derivative [Line Items]
Contract price | $ / bbl	54.20
Production volume covered per month - Oil | bbl	2,000

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Derivatives (Narrative) (Details) - USD ($)	Dec. 31, 2016	Sep. 30, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Fair value of derivative contracts, liability	$ 2,944,534	$ 428,271

XML

Derivatives (Summary Of Derivative Contracts) (Details) - USD ($)		Dec. 31, 2016	Sep. 30, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gross amounts recognized - Current Liabilities	[1]	$ 2,933,947	$ 471,847
Offsetting adjustments - Current Liabilities	[1]		(68,235)
Derivative contracts, net	[1]	2,933,947	403,612
Gross amounts recognized - Non-Current Liabilities	[1]	10,587	29,418
Offsetting adjustments - Non-Current Liabilities	[1]		(4,759)
Derivative contracts, net	[1]	$ 10,587	24,659
Gross amounts recognized - Current Assets	[1]		68,235
Offsetting adjustments - Current Assets	[1]		(68,235)
Gross amounts recognized - Non-Current Assets	[1]		4,759
Offsetting adjustments - Non-Current Assets	[1]		$ (4,759)

[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)	Dec. 31, 2016 USD ($)
Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ (1,138,750)
Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	(1,138,750)
Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	(1,805,784)
Collars [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ (1,805,784)

XML

Fair Value Measurements (Summary Of Unobservable Inputs For Level 3 Fair Value Measurements) (Details)	3 Months Ended
	Dec. 31, 2016 USD ($)
Oil Costless Collars [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Unobservable Input	Oil price volatility curve
Weighted Average	18.53%
Fair Value Assets (Liabilities)	$ (493,394)
Oil Costless Collars [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Range	0.00%
Oil Costless Collars [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Range	27.38%
Natural Gas Costless Collars [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Unobservable Input	Gas price volatility curve
Weighted Average	21.87%
Fair Value Assets (Liabilities)	$ (1,312,390)
Natural Gas Costless Collars [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Range	0.00%
Natural Gas Costless Collars [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Range	39.17%

XML

Fair Value Measurements (Summary Of Reconciliation Of Derivative Contracts Classified As Level 3 Measurements) (Details)	3 Months Ended
	Dec. 31, 2016 USD ($)
Fair Value Disclosures [Abstract]
Balance of Level 3 as of October 1, 2016	$ (316,658)
Total gains or (losses) included in earnings	(1,349,636)
Purchases, issuances and settlements	(139,490)
Balance of Level 3 as of December 31, 2016	$ (1,805,784)

XML

Fair Value Measurements (Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3) (Details) - USD ($)		3 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Producing Properties, Fair Value	[1]		$ 3,152,454
Producing Properties, Impairment		$ 0	$ 3,733,273

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