Through management of its fee mineral and leasehold acreage, the Company’s principal line of business is to explore for, develop, acquire, produce and sell oil, NGL and natural gas. Panhandle’s mineral and leasehold properties and other oil and natural gas interests are all located in the contiguous United States, primarily in Oklahoma, North Dakota, Texas, Arkansas and New Mexico, with properties located in several other states. The Company’s oil, NGL and natural gas production is from interests in 6,496 wells located principally in Oklahoma, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 46%, 9% and 45% of oil, NGL and natural gas revenues were derived from the sale of oil, NGL and natural gas, respectively, in 2019. Approximately 19%, 13% and 68% of the Company’s total sales volumes in 2019 were derived from oil, NGL and natural gas, respectively. Substantially all the Company’s oil, NGL and natural gas production is sold through the operators of the wells. From time to time, the Company sells certain non-material, non-core or small-interest oil and natural gas properties in the normal course of business.

Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Of these estimates and assumptions, management considers the estimation of crude oil, NGL and natural gas reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. The Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of crude oil, NGL and natural gas reserves on an annual basis, with a semi-annual update. These estimates are based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the SEC, the reserve estimates were based on average individual product prices during the 12-month period prior to September 30, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. For impairment purposes, projected future crude oil, NGL and natural gas prices as estimated by management are used. Crude oil, NGL and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Management uses projected future crude oil, NGL and natural gas pricing assumptions to prepare estimates of crude oil, NGL and natural gas reserves used in formulating management’s overall operating decisions.

The Company does not operate its oil and natural gas properties and, therefore, receives actual oil, NGL and natural gas sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, on wells with greater significance to the Company, the most current available production data is gathered from the appropriate operators, and oil, NGL and natural gas index prices local to each well are used to estimate the accrual of revenue on these wells. Timely obtaining production data on all other wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The oil, NGL and natural gas sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, NGL and natural gas. These variables could lead to an over or under accrual of oil, NGL and natural gas sales at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.

Certain amounts (loss (gain) on asset sales and other in the Statements of Operations and presentation of deferred tax assets and liabilities in Note 4: Income Taxes) in the prior years have been reclassified to conform to the current year presentation.

Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.

The Company sells oil, NGL and natural gas to various customers, recognizing revenues as oil, NGL and natural gas is produced and sold. Charges for compression, marketing, gathering and transportation of natural gas are included in lease operating expenses.

Substantially all of the Company’s accounts receivable are due from purchasers of oil, NGL and natural gas or operators of the oil and natural gas properties. Oil, NGL and natural gas sales receivables are generally unsecured. This industry concentration has the potential to impact our overall exposure to credit risk, in that the purchasers of our oil, NGL and natural gas and the operators of the properties in which we have an interest may be similarly affected by changes in economic, industry or other conditions. During 2019, 2018 and 2017 the Company did not have any bad debt expense. The Company’s allowance for uncollectible accounts as of the Balance Sheet dates was not material.

The Company follows the successful efforts method of accounting for oil and natural gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income, if and when the well does not reach commercial production levels. Oil and natural gas mineral and leasehold costs are capitalized when incurred.

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

The Company has entered into 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. 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. 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. These contracts cover only a portion of the Company’s oil and natural gas production and provide only partial price protection against declines in oil and natural gas prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts at September 30, 2019 and 2018, were with Bank of Oklahoma and Koch Supply and Trading LP. The Company’s derivative contracts with Bank of Oklahoma are secured under its credit facility with Bank of Oklahoma. The derivative contracts with Koch are unsecured. The derivative instruments have settled or will settle based on the prices below.

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas fixed price swaps
July - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.960
July - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.950
July - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$2.995
July 2019 - March 2020	100,000 Mmbtu	NYMEX Henry Hub	$2.982
August - December 2019	100,000 Mmbtu	NYMEX Henry Hub	$3.004
January - December 2020	80,000 Mmbtu	NYMEX Henry Hub	$2.750
Oil costless collars
January - December 2019	1,000 Bbls	NYMEX WTI	$50.00 floor / $60.00 ceiling
January - December 2019	2,000 Bbls	NYMEX WTI	$60.00 floor / $69.25 ceiling
July - December 2019	3,000 Bbls	NYMEX WTI	$60.00 floor / $70.75 ceiling
July 2019 - June 2020	2,000 Bbls	NYMEX WTI	$65.00 floor / $76.15 ceiling
January - June 2020	2,000 Bbls	NYMEX WTI	$60.00 floor / $67.00 ceiling
January - December 2020	2,000 Bbls	NYMEX WTI	$55.00 floor / $62.00 ceiling
Oil fixed price swaps
January - December 2019	1,000 Bbls	NYMEX WTI	$56.15
January - December 2019	2,000 Bbls	NYMEX WTI	$56.71
January - December 2019	1,000 Bbls	NYMEX WTI	$58.56
July - December 2019	2,000 Bbls	NYMEX WTI	$56.85
July - December 2019	5,000 Bbls	NYMEX WTI	$58.50
July - December 2019	1,000 Bbls	NYMEX WTI	$60.60
January - December 2020	2,000 Bbls	NYMEX WTI	$55.28
January - December 2020	2,000 Bbls	NYMEX WTI	$58.65
January - December 2020	2,000 Bbls	NYMEX WTI	$60.00

The Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net asset of $2,494,144 as of September 30, 2019, and a net liability of $3,414,016 as of September 30, 2018. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Operations. The portion of the gain (loss) on derivatives settled in cash for 2019, 2018 and 2017 was $196,985 (net received), $1,001,893 (net paid) and $305,410 (net received), respectively.

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

	9/30/2019				9/30/2018
	Fair Value				Fair Value
	Commodity Contracts				Commodity Contracts
	Current Assets		Non-Current Assets		Current Assets			Current Liabilities			Non-Current Liabilities
Gross amounts recognized	$	2,256,639	$	237,505	$	42,150		$	3,106,196		$	349,970
Offsetting adjustments		-		-		(42,150	)		(42,150	)		-
Net presentation on Balance Sheets	$	2,256,639	$	237,505	$	-		$	3,064,046		$	349,970

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

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels.

The Company uses an option pricing valuation model for option derivative contracts that considers various inputs including: future prices, time value, volatility factors, counterparty credit risk and current market and contractual prices for the underlying instruments. The values calculated are then compared to the values given by counterparties for reasonableness.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis.

	Fair Value Measurement at September 30, 2019
	Quoted Prices in Active Markets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total Fair
	(Level 1)		(Level 2)		(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	1,892,954	$	-	$	1,892,954
Derivative Contracts - Collars	$	-	$	601,190	$	-	$	601,190

	Fair Value Measurement at September 30, 2018
	Quoted Prices in Active Markets		Significant Other Observable Inputs			Significant Unobservable Inputs		Total Fair
	(Level 1)		(Level 2)			(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	(2,317,069	)	$	-	$	(2,317,069	)
Derivative Contracts - Collars	$	-	$	(1,096,947	)	$	-	$	(1,096,947	)

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.

	Year Ended September 30,
	2019				2018				2017
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment

Producing Properties ^(a)	$	9,101,032	$	76,824,337	$	-	$	-	$	567,077	$	662,990

^(a)

At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, 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 September 30, 2019, and September 30, 2018, the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short-term maturities of those instruments. Financial instruments include long-term debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

Depreciation, depletion and amortization of the costs of producing oil and natural gas properties are generally computed using the unit-of-production method primarily on an individual property basis using proved or proved developed reserves, as applicable, as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company’s capitalized costs of drilling and equipping all development wells, and those exploratory wells that have found proved reserves, are amortized on a unit-of-production basis over the remaining life of associated proved developed reserves. Lease costs are amortized on a unit-of-production basis over the remaining life of associated total proved reserves. Depreciation of furniture and fixtures is computed using the straight-line method over estimated productive lives of five to eight years.

Non-producing oil and natural gas properties include non-producing minerals, which had a net book value of $9,673,787 and $8,025,015 at September 30, 2019 and 2018, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Oklahoma, North Dakota, Texas, Arkansas and New Mexico. As mentioned, these mineral rights are perpetual and have been accumulated over the 93-year life of the Company. There are approximately 197,468 net acres of non-producing minerals in more than 6,688 tracts owned by the Company. An average tract contains approximately 30 acres, and the average cost per acre is $73. Since inception, the Company has continually generated an interest in several thousand oil and natural gas wells using its ownership of the fee mineral acres as an ownership basis. There continues to be significant drilling and leasing activity on these mineral interests each year. Non-producing minerals are being amortized straight-line over a 33-year period. These assets are considered a long-term investment by the Company, as they do not expire (as do oil and natural gas leases). Given the above, management concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period. Due to the fact that the Company’s mineral ownership consists of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis (by mineral deed).

When a new well is drilled on our mineral acreage, all of the non-producing mineral costs for the associated mineral deed are transferred to producing minerals and are amortized straight-line over a 20-year period (insignificant fields are amortized over 10-year period). Management has historically chosen to move non-producing mineral costs in this manner, as it is very difficult for the Company, as a non-operator, to predict well spacing and timing of drilling on all of the minerals that we have purchased over the long life of the Company. Given that we are moving all of the costs to the first new well drilled on each mineral deed, we believe that a straight-line amortization over a 20-year period is appropriate as these wells and future development will deplete these assets over a fairly long period.

The Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted cash flow as estimated by the Company, market quotes where available or fair value (sales price) less cost to sell if the property is held for sale. The Company's estimate of fair value of its oil and natural gas properties at September 30, 2019, is based on the best information available as of that date, including estimates of forward oil, NGL and natural gas prices and costs along with market quotes for specific assets. The Company’s oil and natural gas properties were reviewed for impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $76,824,337, $0 and $662,990 for 2019, 2018 and 2017, respectively.

At the end of 2019, impairment of $76,560,376 was recorded on our Eagle Ford assets. The remaining $263,961 of impairment was taken on other assets. The impairment on the Eagle Ford assets was caused by the Company making the strategic decision to cease participating with a working interest on its mineral and leasehold acreage going forward and therefore removing all working interest PUDs from the Company’s reserve reports. The removal of the PUDs caused the Eagle Ford assets to fail the step one test for impairment, as its undiscounted cash flows were not high enough to cover the book basis of the assets. These assets were written down to their fair market value as required by GAAP. The Company determined the fair value based on discounted cash flows of the properties as well as active market bids received from interested potential buyers. The discounted cash flows of the properties were prepared using NYMEX strip pricing as of year-end, using a discount rate of 10% for proved developed and assigning no value to undeveloped locations. Market bids received from interested potential buyers corroborated the fair value of the discounted cash flows as of year-end. The fair value was determined to be $9.1 million based on the discounted cash flows and market quotes. The Company decided not to sell the assets after the marketing process was complete, as we believed that the market conditions were not ideal for selling at that time and that the highest and best use of the assets was to continue to own and produce out the Eagle Ford properties.

A further 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.

During the 2019 fiscal year, the Company sold 112 non-core wells and 890 net mineral and non-participating royalty interest acres for $19,515,735 and recorded a net gain on sales of $18,730,197. The total net book value that was removed from the Balance Sheets due to these sales was approximately $786,000. On the Statements of Operations, the net gain is reflected in the Gain on asset sales line item with a balance of $18,973,426 with an offset to the Loss on asset sales line item in the amount of $243,228.

During the 2018 fiscal year, the Company sold 324 non-core marginal wells for $1,085,137 and recorded a net loss on the sales of $660,597. The total net book value that was removed from the Balance Sheets due to these sales was approximately $1.7 million. The loss on sales was included in the Loss on asset sales and other line of the Statements of Operations.

During the 2019 fiscal year, the Company acquired mineral acreage in the cores of the Bakken in North Dakota and the STACK and SCOOP plays in Oklahoma. The Company acquired a total of 790 net mineral acres for $5.7 million or an average of approximately $7,200 per net mineral acre. These mineral purchases were accounted for as asset acquisitions.

During the 2018 fiscal year, the Company acquired mineral acreage in the cores of the Bakken in North Dakota and the STACK and SCOOP plays in Oklahoma. The Company acquired a total of 4,306 net mineral acres for $11.3 million or an average of approximately $2,600 per net mineral acre. These mineral purchases were accounted for as asset acquisitions.

During 2019, 2018 and 2017, interest of $38,606, $89,023 and $168,351, respectively, was included in the Company’s capital expenditures. Interest of $1,995,789, $1,748,101 and $1,275,138, respectively, was charged to expense during those periods. Interest is capitalized using a weighted average interest rate based on the Company’s outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the unit-of-production method.

The following table shows the balances for the years ended September 30, 2019 and 2018, relating to the Company’s accrued liabilities:

The Company owns interests in oil and natural gas properties, which may require expenditures to plug and abandon the wells upon the end of their economic lives. The fair value of legal obligations to retire and remove long-lived assets is recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, this cost is capitalized by increasing the carrying amount of the related properties and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties and equipment is depreciated over the useful life of the remaining asset. The Company does not have any assets restricted for the purpose of settling the asset retirement obligations.

The following table shows the activity for the years ended September 30, 2019 and 2018, relating to the Company’s asset retirement obligations:

As the Company is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Company does not believe the existence of current environmental laws, or interpretations thereof, will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future effects on the Company of new laws or interpretations thereof. Since the Company does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with Panhandle being responsible for its proportionate share of the costs involved (on working interest wells only). Panhandle carries liability and pollution control insurance. However, all risks are not insured due to the availability and cost of insurance.

Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At September 30, 2019 and 2018, there were no such costs accrued.

Earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding, plus unissued, vested directors’ deferred compensation shares during the period.

The Company recognizes current compensation costs for its Deferred Compensation Plan for Non-Employee Directors (the “Plan”). Compensation cost is recognized for the requisite directors’ fees as earned and unissued stock is recorded to each director’s account based on the fair market value of the stock at the date earned. The Plan provides that only upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan may be issued to the director.

In accordance with guidance on accounting for employee stock ownership plans, the Company records the fair market value of the stock contributed into its ESOP as expense.

Restricted stock awards to officers provide for cliff vesting at the end of three years from the date of the awards. These restricted stock awards can be granted based on service time only (non-performance based) or subject to certain share price performance standards (performance based). Restricted stock awards to the non-employee directors provide for quarterly vesting during the calendar year of the award. The fair value of the awards on the grant date is ratably expensed over the vesting period in accordance with accounting guidance.

The estimation of amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax regulations. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the Company’s assets and liabilities.

The Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduced the U.S. federal corporate tax rate from 35% to 21%. As of September 30, 2018, we completed our estimates accounting for the tax effects of the Act. Based on these estimates, we recognized an amount which was included as a component of income tax expense (benefit) from continuing operations in 2018.

We remeasured certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. The amount recorded related to the remeasurement of our deferred tax balance was $12,464,000 income tax benefit.

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. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock-based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the year ended September 30, 2018, was a 672% benefit, as compared to a 25% benefit for the year ended September 30, 2019.

The threshold for recognizing the financial statement effect of a tax position is when it is more likely than not, based on the technical merits, that the position will be sustained by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with a taxing authority. The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2016.

The Company includes interest assessed by the taxing authorities in interest expense and penalties related to income taxes in general and administrative expense on its Statements of Operations. For fiscal September 30, 2019, 2018 and 2017, the Company’s interest and penalties were not material. The Company does not believe it has any significant uncertain tax positions.

Revenue recognition and presentation – In May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes nearly all previously existing revenue recognition guidance under U.S. GAAP. Subsequently, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This new guidance became effective for reporting periods beginning after December 15, 2017. The Company adopted the new revenue recognition and presentation guidance on October 1, 2018, as required. See Note 3: Revenues for discussion of the adoption impact and the applicable disclosures required by the new guidance.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize a lease liability and a right-of-use (ROU) asset on the balance sheet for all leases, including operating leases, with terms in excess of 12 months. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation and disclosure of leasing arrangements by both lessees and lessors. The standard will not apply to our leases of mineral rights to explore for or use oil and natural gas resources, including the intangible rights to explore for those natural resources and rights to use the land in which those natural resources are contained, as these are accounted for under ASC 932. The Company plans to make certain elections permitting us to not reassess whether any expired or existing contracts contained leases, permitting us to not reassess the lease classification for any expired or existing leases (all existing leases that were classified as operating leases in accordance with Topic 840 will be classified as operating leases) and permitting us to not reassess initial direct costs for any existing leases.

The Company has completed the assessment of contracts potentially affected by the new standard and has completed the assessment of the accounting treatment for these leases. The adoption will primarily impact other assets and other liabilities and will also impact ongoing disclosures but will not have a material impact on our balance sheet, results of operations or cash flows. We plan to adopt the new standard on October 1, 2019, the effective date, and as permitted by ASU 2018-11 we will not adjust comparative-period financial statements and will continue to apply the guidance in ASC 840, including its disclosure requirements, in the comparative periods presented prior to adoption.

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

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