Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934 (the “Exchange Act”) as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s board of directors, management and other personnel, 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, and includes those policies and procedures that:
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2017. In making this assessment, the Company’s management used the criteria set forth in
Internal Control – Integrated Framework
(as updated in 2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, management has concluded that, as of September 30, 2017, the Company’s internal control over financial reporting was effective based on those criteria.
Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. This report appears on the following page.
Notes to Financial Statements
September 30, 2017, 2016 and 2015
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
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 Arkansas, New Mexico, North Dakota, Oklahoma and Texas, with properties located in several other states. The Company’s oil, NGL and natural gas production is from interests in 6,095 wells located principally in Arkansas, Oklahoma and Texas. The Company is not the operator of any wells. Approximately 55% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2017. Approximately 74% of the Company’s total sales volumes in 2017 were derived from natural gas. 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.
Basis of Presentation
Certain amounts (income from partnerships, exploration costs, bad debt expense (recovery) and loss (gain) on asset sales and other in the Statements of Operations) in the prior years have been reclassified to conform to the current year presentation.
Use of Estimates
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. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of crude oil, NGL and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, 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
(61)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.
Oil, NGL and Natural Gas Sales and Natural Gas Imbalances
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.
The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a well cannot be recouped through the production of remaining reserves. At September 30, 2017 and 2016, the Company had no material natural gas imbalances.
Accounts Receivable and Concentration of Credit Risk
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
(62)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
economic, industry or other conditions. During 2017 a
nd 2016, the Company’s reserve for bad debt expense was not material.
Oil and Natural Gas Producing Activities
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 commercially produce. Oil and natural gas mineral and leasehold costs are capitalized when incurred.
It is common business practice in the petroleum industry to prepay drilling costs before spudding a well. The Company frequently fulfills these prepayment requirements with cash payments, but at times will utilize letters of credit to meet these obligations. As of September 30, 2017, the Company had no outstanding letters of credit.
Leasing of Mineral Rights
When the Company leases its mineral acreage to a third-party company, it retains a royalty interest in any future revenues from the production and sale of oil, NGL or natural gas, and often receives an up-front, non-refundable, cash payment (lease bonus) in addition to the retained royalty interest. A royalty interest does not bear any portion of the cost of drilling, completing or operating a well; these costs are borne by the working interest owners. The Company sometimes leases only a portion of its mineral acres in a tract and retains the right to participate as a working interest owner with the remainder.
The Company recognizes revenue from mineral lease bonus payments when it has received an executed lease agreement with a third-party company transferring the rights to explore for and produce any oil or natural gas they may find within the term of the lease, the payment has been collected, and the Company has no obligation to refund the payment. The Company accounts for its lease bonuses in accordance with the guidance set forth in ASC 932, and it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral being treated as a gain. The excess of lease bonus above the mineral basis is shown in the lease bonuses and rentals line item on the Company’s Statements of Operations.
Derivatives
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
(63)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
derivative contracts are with Bank of Oklahoma and are secured un
der its credit facility with Bank of Oklahoma. The derivative instruments have settled or will settle based on the prices below.
(64)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Derivative contracts in place as of September 30, 2017
|
|
Production volume
|
|
|
|
|
Contract period
|
|
covered per month
|
|
Index
|
|
Contract price
|
Natural gas costless collars
|
|
|
|
|
|
|
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
|
January - March 2018
|
|
150,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.40 floor / $3.95 ceiling
|
January - December 2018
|
|
40,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.75 floor / $3.35 ceiling
|
January - December 2018
|
|
40,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.75 floor / $3.30 ceiling
|
Natural gas fixed price swaps
|
|
|
|
|
|
|
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
|
August - December 2017
|
|
100,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.095
|
January - March 2018
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.700
|
January - March 2018
|
|
75,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.575
|
January - March 2018
|
|
100,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.520
|
January - December 2018
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.080
|
Oil costless collars
|
|
|
|
|
|
|
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
|
January - June 2018
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$47.50 floor / $52.75 ceiling
|
January - December 2018
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$47.50 floor / $52.50 ceiling
|
January - December 2018
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$48.00 floor / $53.25 ceiling
|
Oil fixed price swaps
|
|
|
|
|
|
|
January - December 2017
|
|
3,000 Bbls
|
|
NYMEX WTI
|
|
$53.89
|
April - December 2017
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$54.20
|
January - March 2018
|
|
4,000 Bbls
|
|
NYMEX WTI
|
|
$54.00
|
January - June 2018
|
|
4,000 Bbls
|
|
NYMEX WTI
|
|
$51.25
|
January - December 2018
|
|
3,000 Bbls
|
|
NYMEX WTI
|
|
$50.72
|
January - December 2018
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$52.02
|
(65)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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 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 $516,159 as of September 30, 2017, and a net liability of $428,271 as of September 30, 2016. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Operations.
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
(66)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's Balance Sheets at September 30, 2017, and September 30, 2016.
The Company has offset all amounts subject to master netting
agreements in the Company's Balance Sheets at September 30, 2017, and September 30, 2016.
|
|
9/30/2017
|
|
|
9/30/2016
|
|
|
|
Fair Value (a)
|
|
|
Fair Value (a)
|
|
|
|
Commodity Contracts
|
|
|
Commodity Contracts
|
|
|
|
Current
Assets
|
|
|
Current Liabilities
|
|
|
Non-Current
Assets
|
|
|
Non-Current
Liabilities
|
|
|
Current
Assets
|
|
|
Current Liabilities
|
|
|
Non-Current
Assets
|
|
|
Non-Current
Liabilities
|
|
Gross amounts recognized
|
|
$
|
735,702
|
|
|
$
|
190,778
|
|
|
$
|
9,439
|
|
|
$
|
38,204
|
|
|
$
|
68,235
|
|
|
$
|
471,847
|
|
|
$
|
4,759
|
|
|
$
|
29,418
|
|
Offsetting adjustments
|
|
|
(190,778
|
)
|
|
|
(190,778
|
)
|
|
|
(9,439
|
)
|
|
|
(9,439
|
)
|
|
|
(68,235
|
)
|
|
|
(68,235
|
)
|
|
|
(4,759
|
)
|
|
|
(4,759
|
)
|
Net presentation on Balance Sheets
|
|
$
|
544,924
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
28,765
|
|
|
$
|
-
|
|
|
$
|
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 only if the impact is deemed material. The impact of credit risk was immaterial for all periods presented.
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.
(67)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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, 2017
|
|
|
|
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
|
|
$
|
-
|
|
|
$
|
364,606
|
|
|
$
|
-
|
|
|
$
|
364,606
|
|
Derivative Contracts - Collars
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
151,553
|
|
|
$
|
151,553
|
|
|
|
Fair Value Measurement at September 30, 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
|
|
$
|
-
|
|
|
$
|
(111,613
|
)
|
|
$
|
-
|
|
|
$
|
(111,613
|
)
|
Derivative Contracts - Collars
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(316,658
|
)
|
|
$
|
(316,658
|
)
|
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 forward prices and 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.
(68)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
The following table represents quantitative disclosures about unobservable inputs for Level 3 Fair Value Measurements.
Instrument
Type
|
|
Unobservable Input
|
|
Range
|
|
Weighted Average
|
|
|
Fair Value
Assets (Liabilities) September 30,
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Collars
|
|
Oil price volatility curve
|
|
0% -
29.06%
|
|
|
14.98
|
%
|
|
$
|
(60,331
|
)
|
Natural Gas Collars
|
|
Gas price volatility curve
|
|
0% - 29.34%
|
|
|
18.13
|
%
|
|
$
|
211,884
|
|
A reconciliation of the Company’s derivative contracts classified as Level 3 measurements is presented below.
|
|
Derivatives
|
|
Net Asset (Liability) Balance of Level 3 as of October 1, 2016
|
|
$
|
(316,658
|
)
|
Total gains or (losses):
|
|
|
|
|
Included in earnings
|
|
|
460,061
|
|
Included in other comprehensive income (loss)
|
|
|
-
|
|
Purchases, issuances and settlements
|
|
|
8,150
|
|
Transfers in and out of Level 3
|
|
|
-
|
|
Net Asset (Liability) Balance of Level 3 as of September 30, 2017
|
|
$
|
151,553
|
|
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,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
Fair Value
|
|
|
Impairment
|
|
|
Fair Value
|
|
|
Impairment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing Properties (a)
|
|
$
|
567,077
|
|
|
$
|
662,990
|
|
|
$
|
9,877,905
|
|
|
$
|
12,001,271
|
|
|
(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, 2017, and September 30, 2016, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which valuation is classified as Level 3 and is based on a valuation technique that requires inputs that
(69)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
a
re 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 de
bt 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 adjustm
ents relating to nonperformance risk for the debt agreements were considered necessary.
Depreciation, Depletion, Amortization and Impairment
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 $3,079,008 and $3,349,567 at September 30, 2017 and 2016, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. As mentioned, these mineral rights are perpetual and have been accumulated over the 91-year life of the Company. There are approximately 198,176 net acres of non-producing minerals in more than 6,284 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $40. 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 each year on these mineral interests. 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 minerals consist 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.
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 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, 2017, is based on the best information available as of that date, including estimates of forward oil, NGL and natural gas prices and costs. 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 $662,990,
(70)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
$12,001,271 and $5,009,191 for 2017, 2016 and 2015, respectively. 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.
At September 30, 2017, the Company had a group of 68 non-core marginal wells that were held for sale pending a final agreement with the buyer. The sale of these assets closed on October 12, 2017, for $557,750. As the selling price was less than the carrying value and these wells met the criteria of held for sale at September 30, 2017, the carrying amount of these assets was written down to fair value less cost to sell and an impairment expense was recognized for $616,711 (included in Provision for impairment line of Statement of Operations). The net amount of assets less accumulated DD&A ($14,929,309 and $14,371,559, respectively) was reclassed from noncurrent assets in Property and equipment to current assets as Assets held for sale on the Balance Sheets as of September 30, 2017.
Capitalized Interest
During
2017, 2016 and 2015
, interest of $168,351, $24,929 and $148,493, respectively, was included in the Company’s capital expenditures. Interest of $1,275,138, $1,344,619 and $1,550,483, 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.
Asset Retirement Obligations
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, 2017 and 2016, relating to the Company’s asset retirement obligations:
|
|
2017
|
|
|
2016
|
|
Asset retirement obligations as of beginning of the year
|
|
$
|
2,958,048
|
|
|
$
|
2,824,944
|
|
Wells acquired or drilled
|
|
|
114,766
|
|
|
|
17,338
|
|
Wells sold or plugged
|
|
|
(548,634
|
)
|
|
|
(12,956
|
)
|
Revisions in estimated cash flows
|
|
|
536,536
|
|
|
|
-
|
|
Accretion of discount
|
|
|
136,173
|
|
|
|
128,722
|
|
Asset retirement obligations as of end of the year
|
|
$
|
3,196,889
|
|
|
$
|
2,958,048
|
|
(71)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
The revisions in estimated cash flows in fiscal 2017 were due to increased plugging charges noted
recently that were higher than previously estimated. As a non-operator, we do not control the plugging of wells in which we have a working interest and are not involved in the negotiation of the terms of the plugging contracts. Our estimate relies on info
rmation that we receive directly from operators as well as relevant information that we can gather from outside sources.
Environmental Costs
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. 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, 2017 and 2016, there were no such costs accrued.
Earnings (Loss) Per Share of Common Stock
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.
Share-based Compensation
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 or five 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
(72)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
quarterly vesting during the calendar year of the award. Th
e fair value of the awards on the grant date is ratably expensed over the vesting period in accordance with accounting guidance.
Income Taxes
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 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 2014.
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, 2017, 2016 and 2015, the Company’s interest and penalties was not material. The Company does not believe it has any significant uncertain tax positions.
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.
(73)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
The Company adopted ASU 2015-03 and ASU 2015-15 as of December 31, 2016. T
he 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 re
ported 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 $141,956 and $263,584 as of September 30, 20
17, 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 $310,900 as of September 30, 2016, 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-K 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 $5,194,290, $8,049,434 and $2,053,900 for the fiscal years ending
September 30, 2017, 2016
and
2015,
res
pectively, 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
(74)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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 Flow
s presented throughout this report on Form 10-K have been adjusted to reflect the ret
roactive 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 $238,000 of excess tax benefits from stock-based compensation in the “Provision (benefit) for income taxes” on the Condensed Statements of Operations in 2017 versus “Capital in excess of par” on the Condensed Balance Sheets in 2016 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 (using shares repurchased) as financing activities on the statement of cash flows (Purchases of Treasury Stock). 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. The adoption of this ASU could cause volatility in the effective tax rate going forward.
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to
(75)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Continue as a Going Concern. The update defined management’s responsibility to evaluate whether substantial doubt exists about an entity’s ability to continue as a
going concern. Professional auditing standards require auditors to evaluate the going concern presumption, but previously there was a lack of guidance in GAAP for financial statement preparers. This update requires management to perform a going concern eva
luation effective for annual periods ending after December 15, 2016, and annual and interim periods thereafter. The Company adopted this standard in 2017 and management does not believe there is substantial doubt about the entity’s ability to continue as a
going concern.
New Accounting Pronouncements yet to be Adopted
In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02,
Leases (Topic 842)
. Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date: 1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and 2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new lease guidance simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. Lessees will no longer be provided with a source of off-balance sheet financing. The guidance is effective for us beginning October 1, 2019, including interim periods within the fiscal year. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this 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 us beginning October 1, 2018, including interim periods within the fiscal year. 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
(76)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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.
2. COMMITMENTS
The Company leases office space in Oklahoma City, Oklahoma, under the terms of an operating lease expiring in April 2020. Future minimum rental payments under the terms of the lease are $206,665, $210,273 and $122,659 in 2018, 2019 and 2020, respectively. Total rent expense incurred by the Company was $206,366 in 2017, $202,083 in 2016 and $198,238 in 2015.
3. INCOME TAXES
The Company’s provision (benefit) for income taxes is detailed as follows:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
314,000
|
|
|
$
|
2,166,000
|
|
|
$
|
2,053,000
|
|
State
|
|
|
-
|
|
|
|
83,000
|
|
|
|
111,000
|
|
|
|
|
314,000
|
|
|
|
2,249,000
|
|
|
|
2,164,000
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
390,000
|
|
|
|
(8,597,000
|
)
|
|
|
2,033,000
|
|
State
|
|
|
(15,000
|
)
|
|
|
(1,363,000
|
)
|
|
|
639,000
|
|
|
|
|
375,000
|
|
|
|
(9,960,000
|
)
|
|
|
2,672,000
|
|
|
|
$
|
689,000
|
|
|
$
|
(7,711,000
|
)
|
|
$
|
4,836,000
|
|
The difference between the provision (benefit) for income taxes and the amount which would result from the application of the federal statutory rate to income before provision (benefit) for income taxes is analyzed below for the years ended September 30:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision (benefit) for income taxes at statutory rate
|
|
$
|
1,477,327
|
|
|
$
|
(6,299,259
|
)
|
|
$
|
4,955,069
|
|
Percentage depletion
|
|
|
(570,801
|
)
|
|
|
(395,649
|
)
|
|
|
(530,783
|
)
|
State income taxes, net of federal provision (benefit)
|
|
|
3,900
|
|
|
|
(683,800
|
)
|
|
|
487,500
|
|
Effect of graduated rates
|
|
|
85,644
|
|
|
|
(86,745
|
)
|
|
|
(62,922
|
)
|
Restricted stock tax benefit
|
|
|
(238,000
|
)
|
|
|
-
|
|
|
|
-
|
|
Deferred directors compensation benefit
|
|
|
(79,000
|
)
|
|
|
-
|
|
|
|
-
|
|
Other
|
|
|
9,930
|
|
|
|
(245,547
|
)
|
|
|
(12,864
|
)
|
|
|
$
|
689,000
|
|
|
$
|
(7,711,000
|
)
|
|
$
|
4,836,000
|
|
(77)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Deferred tax assets and liabilities, resulting from differences between the financial statement carrying amounts and the tax basis of assets and liabilities, consist of the following
at September 30
:
|
|
2017
|
|
|
2016
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Financial basis in excess of tax basis, principally intangible
drilling costs capitalized for financial purposes and
expensed for tax purposes
|
|
$
|
38,185,387
|
|
|
$
|
33,656,415
|
|
Derivative contracts
|
|
|
200,786
|
|
|
|
-
|
|
|
|
|
38,386,173
|
|
|
|
33,656,415
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
State net operating loss carry forwards
|
|
|
655,741
|
|
|
|
259,981
|
|
AMT credit carry forwards
|
|
|
3,499,320
|
|
|
|
-
|
|
Deferred directors' compensation
|
|
|
1,295,333
|
|
|
|
1,273,279
|
|
Restricted stock expense
|
|
|
411,019
|
|
|
|
494,776
|
|
Derivative contracts
|
|
|
-
|
|
|
|
166,597
|
|
Statutory depletion carry forwards
|
|
|
634,405
|
|
|
|
-
|
|
Other
|
|
|
839,348
|
|
|
|
785,775
|
|
|
|
|
7,335,166
|
|
|
|
2,980,408
|
|
Net deferred tax liabilities
|
|
$
|
31,051,007
|
|
|
$
|
30,676,007
|
|
At September 30, 2017, the Company had a deferred tax asset of $595,526 related to Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring from 2029 to 2037. There is no valuation allowance for the OK NOL’s, as management believes they will be utilized before they expire. The AMT carry forwards do not have an expiration date.
4. LONG-TERM DEBT
The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a current borrowing base of $80,000,000 and a maturity date of November 30, 2022. The credit facility is subject to a semi-annual borrowing base determination, wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The facility is secured by certain of the Company’s properties with a net book value of $152,025,984 at September 30, 2017. The interest rate is based on BOK prime plus from 0.375% to 1.250%, or 30 day LIBOR plus from 1.875% to 2.750%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At September 30, 2017, the effective interest rate was 3.72%.
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.
(78)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Determinations of the borrowing base are made semi-annually
(
usually
June and December)
or whenever the bank
s
, in
their sole discre
tion, believe
that there has been a material change in the value of the
Company’s
oil and natural gas properties.
In
October
2017
,
during the renegotiation of our credit facility,
the borrowing base was
rede
te
rmined
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
limit
s
on
the Company’s incurrence of indebtedness, liens,
payment of
dividends and acquisitions of t
reasury stock
. In addition,
the Company
is required
to maintain certain financial ratios
, a current ratio (as defined
by
the
bank agreement – current assets includes availability under outstanding credit facility
) of no less than
1.0
to 1.0 and a funded de
bt to EBITDA (
trailing
12
months as defined by bank agreement – traditional EBITDA with the unrealized gain or loss on derivative contracts also removed from earnings
) of no more than
4.0
to 1.0
. At
September 30, 2017
, the Company was in compliance with th
e covenants of the
loan
agreement
and ha
d
$27,778,000
of availability under its outstanding credit facility.
5. SHAREHOLDERS’ EQUITY
Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan in March 2010, the Board approved purchase of up to $1.5 million of the Company’s Common Stock, from time to time, equal to the aggregate number of shares of Common Stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. Effective May 2014, the board of directors approved for management to make these purchases of the Company’s Common Stock at their discretion. The Board’s approval included an initial authorization to purchase up to $1.5 million of Common Stock, with a provision for subsequent authorizations without specific action by the Board. As the amount of Common Stock purchased under any authorization reaches $1.5 million, another $1.5 million is automatically authorized for Common Stock purchases unless the Board determines otherwise. Pursuant to these resolutions adopted by the Board, the purchase of additional $1.5 million increments of the Company’s Common Stock became authorized and approved effective March 2011, March 2012, and June 2013. As of September 30, 2017, $5,599,643 had been spent under the current program to purchase 370,950 shares. The shares are held in treasury and are accounted for using the cost method.
(79)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
6.
EARNINGS
(LOSS)
PER SHARE
The following table sets forth the computation of earnings (loss) per share.
|
|
Year ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Numerator for basic and diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
3,531,933
|
|
|
$
|
(10,286,884
|
)
|
|
$
|
9,321,341
|
|
Denominator for basic and diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares (including for 2017, 2016
and 2015, unissued, vested directors' shares of
253,603, 263,057 and 246,442, respectively)
|
|
|
16,900,185
|
|
|
|
16,840,856
|
|
|
|
16,768,904
|
|
7. EMPLOYEE STOCK OWNERSHIP PLAN
The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan that serves as the sole retirement plan for all its employees to which the Company makes contributions. Company contributions are made at the discretion of the Board and, to date, all contributions have been made in shares of Company Common Stock. The Company contributions are allocated to all ESOP participants in proportion to their compensation for the plan year, and 100% vesting occurs after three years of service. Any shares that do not vest are treated as forfeitures and are distributed among other vested employees. For contributions of Common Stock, the Company records as expense the fair market value of the stock contributed. The 252,542 shares of the Company’s Common Stock held by the plan as of September 30, 2017, are allocated to individual participant accounts, are included in the weighted average shares outstanding for purposes of earnings-per-share computations and receive dividends.
Contributions to the plan consisted of:
Year
|
|
Shares
|
|
|
Amount
|
|
2017
|
|
|
13,125
|
|
|
$
|
312,380
|
|
2016
|
|
|
11,418
|
|
|
$
|
200,158
|
|
2015
|
|
|
11,455
|
|
|
$
|
185,113
|
|
8. DEFERRED COMPENSATION PLAN FOR DIRECTORS
Annually, independent directors may elect to be included in the Panhandle Oil and Gas Inc. Deferred Directors’ Compensation Plan for Non-Employee Directors (the “Plan”). The Plan provides that each independent 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, if and 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.
(80)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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 Plan be issued to the director. The promise to issue such shares in the future is
an unsecured obligation of the Company.
As of
September 30, 2017
,
there were
261,846
shares
(
272,564
shares at
September 30, 2016
)
recorded under
the Plan.
The
deferred balance outstanding at
September 30, 2017
,
under the Plan
was
$3,459,909
(
$3,403,213
at
September 30, 2016
)
.
Expense
s
totaling
$358,658
,
$329,465
and
$302,353
were
charged
to the
Company’s
results of operations for the years ended
September 30, 2017
,
2016
and
2015
, respectively, and
are
included in general and administrative expense in the accompanying
S
tatement
of Operations
.
9. 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 the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders.
In June 2010, the Company began awarding shares of the Company’s Common Stock as restricted stock (non-performance based) to certain officers. The restricted stock vests at the end of the vesting period and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares was based on the closing price of the shares on their award date and will be recognized as compensation expense ratably over the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury.
In December 2010, the Company also began awarding shares of the Company’s Common Stock, subject to certain share price performance standards (performance based), as restricted stock to certain officers. Vesting of these shares is based on the performance of the market price of the Common Stock over the vesting period. The fair value of the performance shares was estimated on the grant date using a Monte Carlo valuation model that factors in information, including the expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance shares. Compensation expense for the performance shares is a fixed amount determined at the grant date and is recognized over the vesting period regardless of whether performance shares are awarded at the end of the vesting period. Should the shares vest, they are expected to be issued out of shares held in treasury.
In May 2014, the Company also began awarding shares of the Company’s Common Stock as restricted stock (non-performance based) to its non-employee directors. The restricted stock vests quarterly during the calendar year of the award and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares was based on the closing price of the shares on their award date and will be recognized as
(81)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
compensation expense ra
tably over the vesting period. Upon vesting, sh
ares are expected to be issued out of shares held in treasury.
Compensation expense for the restricted stock awards is recognized in G&A.
The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2017, 2016 and 2015, related to the Company’s performance based and non-performance based restricted stock.
|
|
Year Ended September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Performance based, restricted stock
|
|
$
|
233,122
|
|
|
$
|
390,655
|
|
|
$
|
480,159
|
|
Non-performance based, restricted stock
|
|
|
364,818
|
|
|
|
390,824
|
|
|
|
414,968
|
|
Total compensation expense
|
|
$
|
597,940
|
|
|
$
|
781,479
|
|
|
$
|
895,127
|
|
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.
|
|
Unrecognized
Compensation
Cost
|
|
|
Weighted Average
Period
(in years)
|
|
Performance based, restricted stock
|
|
$
|
267,618
|
|
|
|
1.82
|
|
Non-performance based, restricted stock
|
|
|
240,126
|
|
|
|
1.44
|
|
Total
|
|
$
|
507,744
|
|
|
|
|
|
Upon vesting, shares are expected to be issued out of shares held in treasury.
(82)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
A summary of the status of unvested shares of restricted stock awards and changes is presented below:
|
|
Performance
Based
Unvested
Restricted
Shares
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
|
Non-
Performance
Based
Unvested
Restricted
Shares
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
Unvested shares as of September 30,
2014
|
|
|
112,184
|
|
|
$
|
8.42
|
|
|
|
56,353
|
|
|
$
|
15.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
35,485
|
|
|
|
12.18
|
|
|
|
22,028
|
|
|
|
19.25
|
|
Vested
|
|
|
(10,209
|
)
|
|
|
9.73
|
|
|
|
(38,415
|
)
|
|
|
16.58
|
|
Forfeited
|
|
|
(25,209
|
)
|
|
|
9.73
|
|
|
|
-
|
|
|
|
-
|
|
Unvested shares as of September 30,
2015
|
|
|
112,251
|
|
|
$
|
9.20
|
|
|
|
39,966
|
|
|
$
|
16.56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
40,446
|
|
|
|
9.32
|
|
|
|
26,478
|
|
|
|
16.37
|
|
Vested
|
|
|
(10,197
|
)
|
|
|
7.59
|
|
|
|
(23,433
|
)
|
|
|
16.91
|
|
Forfeited
|
|
|
(28,083
|
)
|
|
|
7.59
|
|
|
|
-
|
|
|
|
-
|
|
Unvested shares as of September 30,
2016
|
|
|
114,417
|
|
|
$
|
9.78
|
|
|
|
43,011
|
|
|
$
|
16.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
20,531
|
|
|
|
14.27
|
|
|
|
16,426
|
|
|
|
24.41
|
|
Vested
|
|
|
(34,672
|
)
|
|
|
8.07
|
|
|
|
(28,449
|
)
|
|
|
18.02
|
|
Forfeited
|
|
|
(1,186
|
)
|
|
|
8.07
|
|
|
|
(5,991
|
)
|
|
|
17.04
|
|
Unvested shares as of September 30,
2017
|
|
|
99,090
|
|
|
$
|
11.33
|
|
|
|
24,997
|
|
|
$
|
19.41
|
|
The intrinsic value of the vested shares in 2017 was $1,466,415.
10. INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES
Virtually all oil and natural gas producing activities of the Company are conducted within the contiguous United States (principally in Arkansas, Oklahoma and Texas) and represent substantially all of the business activities of the Company.
The following table shows sales, by percentage, through various operators/purchasers during 2017, 2016 and 2015.
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company A
|
|
|
18
|
%
|
|
|
23
|
%
|
|
|
23
|
%
|
Company B
|
|
|
13
|
%
|
|
|
12
|
%
|
|
|
14
|
%
|
(83)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED)
Aggregate Capitalized Costs
The aggregate amount of capitalized costs of oil and natural gas properties and related accumulated depreciation, depletion and amortization as of September 30 is as follows:
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
Producing properties
|
|
$
|
434,571,516
|
|
|
$
|
434,469,093
|
|
Non-producing minerals
|
|
|
7,243,802
|
|
|
|
7,364,630
|
|
Non-producing leasehold
|
|
|
185,125
|
|
|
|
204,101
|
|
Exploratory wells in progress
|
|
|
-
|
|
|
|
5,917
|
|
|
|
|
442,000,443
|
|
|
|
442,043,741
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(245,640,247
|
)
|
|
|
(251,004,735
|
)
|
Net capitalized costs
|
|
$
|
196,360,196
|
|
|
$
|
191,039,006
|
|
Costs Incurred
For the years ended September 30, the Company incurred the following costs in oil and natural gas producing activities:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition costs
|
|
$
|
20,190
|
|
|
$
|
-
|
|
|
$
|
146,261
|
|
Exploration costs
|
|
|
-
|
|
|
|
21,049
|
|
|
|
898,818
|
|
Development costs
|
|
|
25,382,377
|
|
|
|
5,075,710
|
|
|
|
24,931,571
|
|
|
|
$
|
25,402,567
|
|
|
$
|
5,096,759
|
|
|
$
|
25,976,650
|
|
Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves
The following unaudited information regarding the Company’s oil, NGL and natural gas reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB
.
Proved oil and natural gas reserves are those quantities of oil and natural gas which, by analysis of geosciences 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 that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an
(84)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, exc
luding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as pro
ved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oi
l or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering
or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved
oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economical
ly through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable
than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program
was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.
The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2017, 2016 and 2015.
The Company’s net proved oil, NGL and natural gas reserves, which are located in the contiguous United States, as of September 30, 2017, 2016 and 2015, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.
All of the reserve estimates are reviewed and approved by our Vice President of Operations, Freda Webb, who reports directly to our President and CEO. Ms. Webb holds a Bachelor of Science Degree in Mechanical Engineering from the University of Oklahoma, a Master of Science Degree in Petroleum Engineering from the University of Southern California and a Professional Engineering License in Petroleum Engineering in the State of Oklahoma. Ms. Webb has more than 35 years of experience in the oil and gas industry. Before joining the Company, she was sole proprietor of a consulting petroleum engineering firm and a mineral acquisition company. Ms. Webb held various positions of increasing responsibility at
(85)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Southwestern Energy Company and Occidental Petroleum Corporation, with reservoir engineering assignments in several field
locations across the United States. She is an active member of the Society of Petroleum Engineers (SPE).
Our Vice President of Operations and internal staff work closely with our Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. We provide historical information (such as ownership interest, oil and gas production, well test data, commodity prices, operating costs and handling fees, and development costs) for all properties to our Independent Consulting Petroleum Engineers. Throughout the year, our team meets regularly with representatives of our Independent Consulting Petroleum Engineers to review properties and discuss methods and assumptions.
When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data was available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.
Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure and gas-oil ratio behavior, was used in the estimation of reserves.
For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.
Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available.
(86)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Net quantities of proved, developed and undeveloped oil, NGL and natural gas reserves are summarized as follows:
|
|
Proved Reserves
|
|
|
|
Oil
|
|
|
NGL
|
|
|
Natural Gas
|
|
|
Total
|
|
|
|
(Barrels)
|
|
|
(Barrels)
|
|
|
(Mcf)
|
|
|
Bcfe
|
|
September 30, 2014
|
|
|
7,569,579
|
|
|
|
3,040,181
|
|
|
|
142,492,360
|
|
|
|
206.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
(1,697,309
|
)
|
|
|
(425,300
|
)
|
|
|
(31,273,207
|
)
|
|
|
(44.0
|
)
|
Acquisitions (divestitures)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions, discoveries and other additions
|
|
|
1,619,285
|
|
|
|
516,679
|
|
|
|
18,740,114
|
|
|
|
31.6
|
|
Production
|
|
|
(453,125
|
)
|
|
|
(210,960
|
)
|
|
|
(9,745,223
|
)
|
|
|
(13.7
|
)
|
September 30, 2015
|
|
|
7,038,430
|
|
|
|
2,920,600
|
|
|
|
120,214,044
|
|
|
|
180.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
(1,552,010
|
)
|
|
|
(1,192,143
|
)
|
|
|
(47,068,144
|
)
|
|
|
(63.5
|
)
|
Acquisitions (divestitures)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions, discoveries and other additions
|
|
|
303,922
|
|
|
|
65,306
|
|
|
|
16,864,075
|
|
|
|
19.1
|
|
Production
|
|
|
(364,252
|
)
|
|
|
(171,060
|
)
|
|
|
(8,284,377
|
)
|
|
|
(11.5
|
)
|
September 30, 2016
|
|
|
5,426,090
|
|
|
|
1,622,703
|
|
|
|
81,725,598
|
|
|
|
124.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
253,481
|
|
|
|
407,250
|
|
|
|
13,651,501
|
|
|
|
17.6
|
|
Acquisitions (divestitures)
|
|
|
(37,724
|
)
|
|
|
(12,953
|
)
|
|
|
(669,064
|
)
|
|
|
(1.0
|
)
|
Extensions, discoveries and other additions
|
|
|
178,497
|
|
|
|
541,557
|
|
|
|
34,681,614
|
|
|
|
39.0
|
|
Production
|
|
|
(310,677
|
)
|
|
|
(173,858
|
)
|
|
|
(8,194,529
|
)
|
|
|
(11.1
|
)
|
September 30, 2017
|
|
|
5,509,667
|
|
|
|
2,384,699
|
|
|
|
121,195,120
|
|
|
|
168.6
|
|
The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2017 - $46.31/Bbl, $17.55/Bbl, $2.81/Mcf; September 30, 2016 - $36.77/Bbl, $12.22/Bbl, $1.97/Mcf; September 30, 2015 - $55.27/Bbl, $19.10/Bbl, $2.84/Mcf.
The revisions of previous estimates from 2016 to 2017 were primarily the result of:
|
•
|
Positive pricing revisions of 17.9 Bcfe, resulting from the extension of projected economic limits than projected in 2016: proved developed revisions of 17.3 Bcfe and PUD revisions of 0.6 Bcfe.
|
|
•
|
Negative performance revisions of 0.3 Bcfe.
|
The divestiture of 1.0 Bcfe in marginal properties located in southwestern Oklahoma.
(87)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Extensions, discoveries and other additions from 2016 to 2017 are principally attributable to:
|
•
|
Proved developed reserve extensions, discoveries and other additions of 9.9 Bcfe principally resulting from the Company’s participation in six wells in the liquids rich portion of the Anadarko Woodford Shale in Canadian County, Oklahoma.
|
|
•
|
The addition of 29.1 Bcfe of PUD reserves, all are within the Company’s active drilling program areas of the Anadarko Woodford Shale (Cana, STACK and SCOOP) and southeastern Oklahoma Woodford.
|
|
|
Proved Developed Reserves
|
|
|
Proved Undeveloped Reserves
|
|
|
|
Oil
|
|
|
NGL
|
|
|
Natural
Gas
|
|
|
Oil
|
|
|
NGL
|
|
|
Natural
Gas
|
|
|
|
(Barrels)
|
|
|
(Barrels)
|
|
|
(Mcf)
|
|
|
(Barrels)
|
|
|
(Barrels)
|
|
|
(Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2015
|
|
|
2,725,077
|
|
|
|
1,466,834
|
|
|
|
82,899,159
|
|
|
|
4,313,353
|
|
|
|
1,453,766
|
|
|
|
37,314,885
|
|
September 30, 2016
|
|
|
1,980,519
|
|
|
|
1,095,256
|
|
|
|
62,929,047
|
|
|
|
3,445,571
|
|
|
|
527,447
|
|
|
|
18,796,551
|
|
September 30, 2017
|
|
|
2,201,528
|
|
|
|
1,768,425
|
|
|
|
87,861,043
|
|
|
|
3,308,139
|
|
|
|
616,274
|
|
|
|
33,334,077
|
|
The following details the changes in proved undeveloped reserves for 2017 (Mcfe):
Beginning proved undeveloped reserves
|
|
|
42,634,659
|
|
Proved undeveloped reserves transferred to proved developed
|
|
|
(15,670,848
|
)
|
Revisions
|
|
|
819,338
|
|
Extensions and discoveries
|
|
|
29,097,406
|
|
Purchases
|
|
|
-
|
|
Ending proved undeveloped reserves
|
|
|
56,880,555
|
|
Beginning PUD reserves were 42.6 Bcfe. A total of 15.7 Bcfe (37% of the beginning balance) was transferred to proved developed producing during 2017. The 0.8 Bcfe (2% of the beginning balance) of positive revisions to PUD reserves were pricing revisions of 0.6 Bcfe and performance revision of 0.2 Bcfe. No PUD locations from 2013 remain in the PUD category. We anticipate that all the Company’s PUD locations will be drilled and converted to PDP within five years of the date they were added. However, PUD locations and associated reserves, which are no longer projected to be drilled within five years from the date they were added to PUD reserves, will be removed as revisions at the time that determination is made. In the event that there are undrilled PUD locations at the end of the five-year period, it is our intent to remove the reserves associated with those locations from our proved reserves as revisions. The Company added 29.1 Bcfe of PUD reserves in 2017 within the Company’s active drilling program areas of the Anadarko Woodford Shale (Cana, STACK, SCOOP) and southeastern Oklahoma Woodford Shale.
(88)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Standardized Measure of Discounted Future Net Cash Flows
Accounting Standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below.
Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, NGL and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced, based on continuation of the economic conditions applied for such year.
Estimated future income taxes are computed using current statutory income tax rates, including consideration for the current tax basis of the properties and related carry forwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
637,509,599
|
|
|
$
|
380,263,695
|
|
|
$
|
786,295,155
|
|
Future production costs
|
|
|
(256,193,675
|
)
|
|
|
(182,948,045
|
)
|
|
|
(311,933,151
|
)
|
Future development and asset retirement costs
|
|
|
(93,133,683
|
)
|
|
|
(72,431,842
|
)
|
|
|
(124,857,957
|
)
|
Future income tax expense
|
|
|
(102,193,819
|
)
|
|
|
(38,674,100
|
)
|
|
|
(123,007,909
|
)
|
Future net cash flows
|
|
|
185,988,422
|
|
|
|
86,209,708
|
|
|
|
226,496,138
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10% annual discount
|
|
|
(105,155,847
|
)
|
|
|
(56,439,589
|
)
|
|
|
(144,904,927
|
)
|
Standardized measure of discounted future net
cash flows
|
|
$
|
80,832,575
|
|
|
$
|
29,770,119
|
|
|
$
|
81,591,211
|
|
(89)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Changes in the standardized measure of discounted future net cash flows are as follows:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Beginning of year
|
|
$
|
29,770,119
|
|
|
$
|
81,591,211
|
|
|
$
|
204,782,504
|
|
Changes resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of oil, NGL and natural gas, net of
production costs
|
|
|
(25,783,055
|
)
|
|
|
(16,749,632
|
)
|
|
|
(35,359,204
|
)
|
Net change in sales prices and production costs
|
|
|
37,186,619
|
|
|
|
(86,198,778
|
)
|
|
|
(211,336,729
|
)
|
Net change in future development and asset
retirement costs
|
|
|
(7,939,156
|
)
|
|
|
21,636,258
|
|
|
|
9,569,985
|
|
Extensions and discoveries
|
|
|
38,582,908
|
|
|
|
11,640,704
|
|
|
|
34,327,400
|
|
Revisions of quantity estimates
|
|
|
15,282,587
|
|
|
|
(41,716,689
|
)
|
|
|
(51,375,950
|
)
|
Acquisitions (divestitures) of reserves-in-place
|
|
|
(962,667
|
)
|
|
|
-
|
|
|
|
-
|
|
Accretion of discount
|
|
|
4,789,294
|
|
|
|
14,424,032
|
|
|
|
37,000,855
|
|
Net change in income taxes
|
|
|
(27,070,430
|
)
|
|
|
44,533,277
|
|
|
|
102,592,290
|
|
Change in timing and other, net
|
|
|
16,976,356
|
|
|
|
609,736
|
|
|
|
(8,609,940
|
)
|
Net change
|
|
|
51,062,456
|
|
|
|
(51,821,092
|
)
|
|
|
(123,191,293
|
)
|
End of year
|
|
$
|
80,832,575
|
|
|
$
|
29,770,119
|
|
|
$
|
81,591,211
|
|
12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following is a summary of the Company’s unaudited quarterly results of operations.
|
|
Fiscal 2017
|
|
|
|
Quarter Ended
|
|
|
|
December
31
|
|
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
Revenues
|
|
$
|
7,036,643
|
|
|
$
|
13,964,288
|
|
|
$
|
12,437,186
|
|
|
$
|
12,896,932
|
|
Income (loss) before provision for
income taxes
|
|
$
|
(3,345,392
|
)
|
|
$
|
4,273,433
|
|
|
$
|
1,827,758
|
|
|
$
|
1,465,134
|
|
Net income (loss)
|
|
$
|
(2,238,392
|
)
|
|
$
|
3,470,433
|
|
|
$
|
1,260,758
|
|
|
$
|
1,039,134
|
|
Earnings (loss) per share
|
|
$
|
(0.13
|
)
|
|
$
|
0.21
|
|
|
$
|
0.07
|
|
|
$
|
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal 2016
|
|
|
|
Quarter Ended
|
|
|
|
December 31
|
|
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
Revenues
|
|
$
|
11,445,856
|
|
|
$
|
7,592,852
|
|
|
$
|
9,864,090
|
|
|
$
|
10,157,985
|
|
Income (loss) before provision for
income taxes
|
|
$
|
(5,167,118
|
)
|
|
$
|
(12,013,161
|
)
|
|
$
|
(1,730,795
|
)
|
|
$
|
913,190
|
|
Net income (loss)
|
|
$
|
(2,799,118
|
)
|
|
$
|
(7,438,161
|
)
|
|
$
|
(786,795
|
)
|
|
$
|
737,190
|
|
Earnings (loss) per share
|
|
$
|
(0.17
|
)
|
|
$
|
(0.44
|
)
|
|
$
|
(0.05
|
)
|
|
$
|
0.05
|
|
(90)