Company management 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, 2018. 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, 2018, 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, 2018, 2017 and 2016
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 6,079 wells located principally in Arkansas, Oklahoma and Texas. The Company does not operate any wells. Approximately 45% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2018. Approximately 71% of the Company’s total sales volumes in 2018 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.
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. 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
(65)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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, 2018 and 2017, 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 economic, industry or other conditions. During 2018, 2017 and 2016 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.
(66
)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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 reach commercial production levels. 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, 2018, 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 interest in a tract. The Company 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 derivative contracts at September 30, 2018 and 2017, were with Bank of Oklahoma and are secured under its credit facility with Bank of Oklahoma. The derivative instruments have settled or will settle based on the prices below.
(67
)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Derivative contracts in place as of September 30, 2018
|
|
Production volume
|
|
|
|
|
Contract period
|
|
covered per month
|
|
Index
|
|
Contract price
|
Natural gas costless collars
|
|
|
|
|
|
|
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
|
April - December 2018
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.80 floor / $3.15 ceiling
|
Natural gas fixed price swaps
|
|
|
|
|
|
|
January - December 2018
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.080
|
April - December 2018
|
|
40,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.910
|
July - December 2018
|
|
100,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.835
|
July - December 2018
|
|
100,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.925
|
July - December 2018
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.988
|
July 2018 - March 2019
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.065
|
January - July 2019
|
|
100,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.867
|
Oil costless collars
|
|
|
|
|
|
|
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
|
January - December 2018
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$50.00 floor / $55.75 ceiling
|
July - December 2018
|
|
3,000 Bbls
|
|
NYMEX WTI
|
|
$50.00 floor / $58.00 ceiling
|
January - June 2019
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$55.00 floor / $63.45 ceiling
|
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
|
January - June 2020
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$60.00 floor / $67.00 ceiling
|
Oil fixed price swaps
|
|
|
|
|
|
|
January - December 2018
|
|
3,000 Bbls
|
|
NYMEX WTI
|
|
$50.72
|
January - December 2018
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$52.02
|
April - December 2018
|
|
4,000 Bbls
|
|
NYMEX WTI
|
|
$54.14
|
July - December 2018
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$58.20
|
January - June 2019
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$59.69
|
January - June 2019
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$57.15
|
January - June 2019
|
|
3,000 Bbls
|
|
NYMEX WTI
|
|
$58.02
|
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
|
(68
)
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
|
(69
)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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 liability of $3,414,016 as of September 30, 2018, and a net asset of $516,159 as of September 30, 2017. 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 2018, 2017 and 2016 was $1,001,893 (net paid), $305,410 (net received) and $4,552,680 (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, 2018, and September 30, 2017. The Company has offset all amounts subject to master netting agreements in the Company's Balance Sheets at September 30, 2018, and September 30, 2017.
|
|
9/30/2018
|
|
|
9/30/2017
|
|
|
|
Fair Value
|
|
|
Fair Value
|
|
|
|
Commodity Contracts
|
|
|
Commodity Contracts
|
|
|
|
Current
Assets
|
|
|
Current Liabilities
|
|
|
Non-Current
Liabilities
|
|
|
Current
Assets
|
|
|
Current Liabilities
|
|
|
Non-Current
Assets
|
|
|
Non-Current
Liabilities
|
|
Gross amounts recognized
|
|
$
|
42,150
|
|
|
$
|
3,106,196
|
|
|
$
|
349,970
|
|
|
$
|
735,702
|
|
|
$
|
190,778
|
|
|
$
|
9,439
|
|
|
$
|
38,204
|
|
Offsetting adjustments
|
|
|
(42,150
|
)
|
|
|
(42,150
|
)
|
|
|
-
|
|
|
|
(190,778
|
)
|
|
|
(190,778
|
)
|
|
|
(9,439
|
)
|
|
|
(9,439
|
)
|
Net presentation on Balance Sheets
|
|
$
|
-
|
|
|
$
|
3,064,046
|
|
|
$
|
349,970
|
|
|
$
|
544,924
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
28,765
|
|
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 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:
|
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur with
|
(70)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
|
sufficient frequency and volume to provide pricing information on an ongoing basi
s.
|
Level 2:
|
Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and, as of the fourth quarter of 2018, commodity options (i.e. price collars).
|
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.
Level 3:
|
Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and unobservable (or less observable) from objective sources (supported by little or no market activity).
|
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, 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
|
)
|
|
|
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
|
|
(71
)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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, 2017
|
|
$
|
151,553
|
|
Total gains or (losses):
|
|
|
|
|
Included in earnings
|
|
|
(877,307
|
)
|
Included in other comprehensive income (loss)
|
|
|
-
|
|
Purchases, issuances and settlements
|
|
|
(371,193
|
)
|
Transfers in and out of Level 3 (i)
|
|
|
1,096,947
|
|
Net Asset (Liability) Balance of Level 3 as of September 30, 2018
|
|
$
|
-
|
|
|
(i)
|
During the fourth quarter of 2018, we transferred $1,096,947 of derivative collars out of Level 3 hierarchy, into Level 2 hierarchy as a result of our ability to obtain volatility inputs from direct observable sources.
|
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,
|
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|
|
Fair Value
|
|
|
Impairment
|
|
|
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, 2018, and September 30, 2017,
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.
(72
)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Properties and Equipment
Depreciation, Depletion and Amortization
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 $8,025,015 and $3,079,008 at September 30, 2018 and 2017, 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 92-year life of the Company. There are approximately 198,360 net acres of non-producing minerals in more than 6,749 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $62. 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 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.
Impairment
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, 2018, 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 $0, $662,990 and $12,001,271 for 2018, 2017 and 2016, 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.
(73
)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Divestitures
During the 2018 fiscal year, the Company sold 324 non-core marginal wells for $1,085,137 and recorded a 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 (gain) on asset sales and other line of the Statements of Operations. All of the wells included in the Assets held for sale line item on the Balance Sheets at September 30, 2017, were sold during the first quarter of 2018.
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.
Capitalized Interest
During
2018, 2017 and 2016
, interest of $89,023, $168,351 and $24,929, respectively, was included in the Company’s capital expenditures. Interest of $1,748,101, $1,275,138 and $1,344,619, 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, 2018 and 2017, relating to the Company’s asset retirement obligations:
|
|
2018
|
|
|
2017
|
|
Asset retirement obligations as of beginning of the year
|
|
$
|
3,196,889
|
|
|
$
|
2,958,048
|
|
Wells acquired or drilled
|
|
|
17,215
|
|
|
|
114,766
|
|
Wells sold or plugged
|
|
|
(542,892
|
)
|
|
|
(548,634
|
)
|
Revisions in estimated cash flows
|
|
|
-
|
|
|
|
536,536
|
|
Accretion of discount
|
|
|
138,166
|
|
|
|
136,173
|
|
Asset retirement obligations as of end of the year
|
|
$
|
2,809,378
|
|
|
$
|
3,196,889
|
|
(74
)
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 information that we can gather from outside sources as well as relevant information that we receive directly from operators.
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, 2018 and 2017, 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 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
(75)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
based). Restricted stock awards to the non-employ
ee 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.
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 Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduces the U.S. federal corporate tax rate from 35% to 21%, requires companies to pay a one-time transition tax on earnings of certain foreign subsidiaries that were previously tax deferred and creates new taxes on certain foreign sourced earnings. As of September 30, 2018, we have completed our estimates accounting for the tax effects of enactment of the Act. Based on these estimates, we recognized an amount which is included as a component of income tax expense (benefit) from continuing operations.
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 has a year end of September 30. Because this differs from a calendar year end, we have calculated the current year’s federal tax provision using a blended rate of 24.53% to adjust for one quarter of our fiscal year being under the old rate of 35% and the remaining three quarters being under the new rate of 21%. The impact of using a blended rate versus the old rate in the current year resulted in a federal tax benefit of $198,581.
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
(76)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
loss is relatively small, the proportional effect of these items on the effective tax rate may be signific
ant.
The effective tax rate for the
year
ended
September
30, 2018, was a
672
% benefit as compared to a 1
6
% provision for the
year
ended
September
30, 2017.
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 2015.
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, 2018, 2017 and 2016, 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 January 2017, the FASB issued ASU 2017-01, which changed the definition of a business. The new guidance requires an entity to first evaluate whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets. If that threshold is met, the set of assets and activities is not a business. If it’s not met, the entity evaluates whether the set meets the definition of a business. The new definition requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue recognition guidance. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. The ASU was applied prospectively to transactions occurring within the period of adoption. Early adoption is permitted, including for interim or annual periods for which the financial statements have not been issued or made available for issuance.
The Company early adopted ASU 2017-01 during the third quarter ended June 30, 2018.
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-
(77)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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. T
he 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 potent
ial 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.
This update is not expected to have a material impact 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.
Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis.
The standard is effective for us beginning October 1, 2018. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements and utilizes a cumulative effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Panhandle intends to use the modified retrospective method upon adoption.
The Company has completed its evaluation of the impact of the new standard and related interpretive guidance on its financial statements, accounting policies, internal controls, and disclosures. Based on our assessments, the standard is not expected to have a material effect on the timing or measurement of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures and internal controls over financial reporting.
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.
(78
)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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 $210,273, $122,659 and $0 in 2019, 2020 and 2021, respectively. Total rent expense incurred by the Company was $215,803 in 2018, $206,366 in 2017 and $202,083 in 2016.
3. INCOME TAXES
The Company’s provision (benefit) for income taxes is detailed as follows:
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
204,000
|
|
|
$
|
314,000
|
|
|
$
|
2,166,000
|
|
State
|
|
|
20,000
|
|
|
|
-
|
|
|
|
83,000
|
|
|
|
|
224,000
|
|
|
|
314,000
|
|
|
|
2,249,000
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(13,240,000
|
)
|
|
|
390,000
|
|
|
|
(8,597,000
|
)
|
State
|
|
|
277,000
|
|
|
|
(15,000
|
)
|
|
|
(1,363,000
|
)
|
|
|
|
(12,963,000
|
)
|
|
|
375,000
|
|
|
|
(9,960,000
|
)
|
|
|
$
|
(12,739,000
|
)
|
|
$
|
689,000
|
|
|
$
|
(7,711,000
|
)
|
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:
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
Provision (benefit) for income taxes at statutory rate
|
|
$
|
465,253
|
|
|
$
|
1,477,327
|
|
|
$
|
(6,299,259
|
)
|
Percentage depletion
|
|
|
(577,780
|
)
|
|
|
(570,801
|
)
|
|
|
(395,649
|
)
|
State income taxes, net of federal provision (benefit)
|
|
|
36,980
|
|
|
|
3,900
|
|
|
|
(683,800
|
)
|
Effect of graduated rates
|
|
|
-
|
|
|
|
85,644
|
|
|
|
(86,745
|
)
|
Restricted stock tax benefit
|
|
|
(69,000
|
)
|
|
|
(238,000
|
)
|
|
|
-
|
|
Deferred directors compensation benefit
|
|
|
(134,000
|
)
|
|
|
(79,000
|
)
|
|
|
-
|
|
Law change (a)
|
|
|
(12,464,000
|
)
|
|
|
-
|
|
|
|
-
|
|
Other
|
|
|
3,547
|
|
|
|
9,930
|
|
|
|
(245,547
|
)
|
|
|
$
|
(12,739,000
|
)
|
|
$
|
689,000
|
|
|
$
|
(7,711,000
|
)
|
(79
)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
|
(a)
|
This is the tax effect of the Tax Cuts and Jobs Act (enacted in December 2017) on our deferred tax liabilities.
This Act reduced the U
.
S
.
federal corporate tax rate from
35%
to
21%
.
|
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:
|
|
2018
|
|
|
2017
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Financial basis in excess of tax basis, principally intangible
drilling costs capitalized for financial purposes and
expensed for tax purposes
|
|
$
|
24,560,165
|
|
|
$
|
38,185,387
|
|
Derivative contracts
|
|
|
-
|
|
|
|
200,786
|
|
|
|
|
24,560,165
|
|
|
|
38,386,173
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
State net operating loss carry forwards
|
|
|
551,435
|
|
|
|
655,741
|
|
AMT credit carry forwards
|
|
|
2,936,457
|
|
|
|
3,499,320
|
|
Deferred directors' compensation
|
|
|
725,971
|
|
|
|
1,295,333
|
|
Restricted stock expense
|
|
|
249,610
|
|
|
|
411,019
|
|
Derivative contracts
|
|
|
878,767
|
|
|
|
-
|
|
Statutory depletion carry forwards
|
|
|
-
|
|
|
|
634,405
|
|
Other
|
|
|
1,129,918
|
|
|
|
839,348
|
|
|
|
|
6,472,158
|
|
|
|
7,335,166
|
|
Net deferred tax liabilities
|
|
$
|
18,088,007
|
|
|
$
|
31,051,007
|
|
At September 30, 2018, the Company had a deferred tax asset of $497,752 related to Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring from 2031 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. The corporate alternative minimum tax was repealed by The Tax Cuts and Jobs Act (enacted on December 22, 2017). Taxpayers with AMT credit carryovers can use the credits to offset regular tax liability for any taxable year. In addition, the AMT credit is refundable in any taxable year beginning after 2017 and before 2022 in an amount equal to 50% (100% in the case of taxable years beginning in 2021) of the excess of the minimum tax credit for the taxable year over the amount of the credit allowable for the year against regular tax liability. Thus, the Company’s entire AMT credit carryforward amounts are fully refundable by 2023.
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,
(80)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
wherei
n 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
$135,994,289
at
September 30, 2018
. The interest rate
is based on BOK prime plus from
0.50%
to
1.25%
, or 30 day LIBOR plus from
2.00%
to
2.75%
. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan bal
ance 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, 2018
, the effective interest rate was
4.34%
.
The Company’s debt is recorded at the carrying amount on its balance sheet. The carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates.
Determinations of the borrowing base are made semi-annually (usually June and December) or whenever the banks, in their sole discretion, believe that there has been a material change in the value of the Company’s oil and natural gas properties. The borrowing base for the credit facility was redetermined in July 2018 by the banks and left unchanged at
$80,000,000. The loan agreement contains customary covenants, which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of treasury stock. The loan agreement sets limits on dividend payments and stock repurchases if those payments would cause the leverage ratio to go above 2.75 to 1.0. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined by the bank agreement – current assets includes availability under outstanding credit facility
) of no less than 1.0 to 1.0 and a funded debt to EBITDA (trailing 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, 2018, the Company was in compliance with the covenants of the loan agreement and had $29,000,000 of availability under its outstanding credit facility.
5. STOCKHOLDERS’ EQUITY
Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan in March 2010, as amended in May 2018, the board of directors approved to continue to allow management to repurchase up to $1.5 million of the Company’s common stock at their discretion. The repurchase of an additional $1.5 million of the Company’s common stock continues to be authorized and approved effective when the previous amount is utilized. The Board added language to clarify that this is intended to be an evergreen provision. The number of shares allowed to be purchased by the Company under the repurchase program is no longer capped at an amount equal to the aggregate number of shares of common stock (i) awarded pursuant to the Company’s Amended 2010 Restricted Stock Plan, (ii) contributed by the Company to its ESOP, and (iii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. As of September 30, 2018, $1,219,228 had been spent to purchase 63,404 shares. The shares are held in treasury and are accounted for using the cost method.
(81
)
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,
|
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
Numerator for basic and diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
14,635,669
|
|
|
$
|
3,531,933
|
|
|
$
|
(10,286,884
|
)
|
Denominator for basic and diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares (including for 2018, 2017
and 2016, unissued, vested directors' shares of
205,736, 253,603 and 263,057, respectively)
|
|
|
16,952,664
|
|
|
|
16,900,185
|
|
|
|
16,840,856
|
|
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. Compensation expense is equal to the contributions for each year. The 247,667 shares of the Company’s Common Stock held by the plan as of September 30, 2018, 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
|
|
2018
|
|
|
20,632
|
|
|
$
|
382,174
|
|
2017
|
|
|
13,125
|
|
|
$
|
312,380
|
|
2016
|
|
|
11,418
|
|
|
$
|
200,158
|
|
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, when issued, over annual time periods up to ten years. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers. Only
(82)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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, 2018
,
there wer
e
212,574
shares
(
261,846
shares at
September 30, 2017
)
recorded under
the Plan.
The
deferred balance outstanding at
September 30, 2018
,
under the Plan
was
$2,950,405
(
$3,459,909
at
September 30, 2017
)
.
Expense
s
totaling
$301,715
,
$358,658
and
$329,465
were
charged
to the
Company’s
results of operations for the years ended
September 30, 2018
,
2017
and
2016
, 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 awards 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
(83)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
compensation expense ra
tably over the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury.
Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur.
The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2018, 2017 and 2016, related to the Company’s performance based and non-performance based restricted stock.
|
|
Year Ended September 30,
|
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
Performance based, restricted stock
|
|
$
|
276,272
|
|
|
$
|
233,122
|
|
|
$
|
390,655
|
|
Non-performance based, restricted stock
|
|
|
379,142
|
|
|
|
364,818
|
|
|
|
390,824
|
|
Total compensation expense
|
|
$
|
655,414
|
|
|
$
|
597,940
|
|
|
$
|
781,479
|
|
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
|
|
$
|
321,389
|
|
|
|
1.79
|
|
Non-performance based, restricted stock
|
|
|
274,666
|
|
|
|
1.50
|
|
Total
|
|
$
|
596,055
|
|
|
|
|
|
Upon vesting, shares are expected to be issued out of shares held in treasury.
(84
)
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
Awards
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
|
Non-
Performance
Based
Unvested
Restricted
Shares
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
29,099
|
|
|
|
11.34
|
|
|
|
19,918
|
|
|
|
20.77
|
|
Vested
|
|
|
(35,485
|
)
|
|
|
12.18
|
|
|
|
(16,248
|
)
|
|
|
19.34
|
|
Forfeited
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Unvested shares as of September 30,
2018
|
|
|
92,704
|
|
|
$
|
11.00
|
|
|
|
28,667
|
|
|
$
|
20.40
|
|
The intrinsic value of the vested shares in 2018 was $1,047,761.
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 2018, 2017 and 2016.
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
Company A
|
|
|
24
|
%
|
|
|
18
|
%
|
|
|
23
|
%
|
Company B
|
|
|
16
|
%
|
|
|
3
|
%
|
|
|
3
|
%
|
Company C
|
|
|
11
|
%
|
|
|
8
|
%
|
|
|
2
|
%
|
Company D
|
|
|
7
|
%
|
|
|
13
|
%
|
|
|
12
|
%
|
(85
)
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:
|
|
2018
|
|
|
2017
|
|
Producing properties
|
|
$
|
427,448,584
|
|
|
$
|
434,571,516
|
|
Non-producing minerals
|
|
|
12,378,395
|
|
|
|
7,243,802
|
|
Non-producing leasehold
|
|
|
185,124
|
|
|
|
185,125
|
|
Exploratory wells in progress
|
|
|
-
|
|
|
|
-
|
|
|
|
|
440,012,103
|
|
|
|
442,000,443
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(242,169,604
|
)
|
|
|
(245,640,247
|
)
|
Net capitalized costs
|
|
$
|
197,842,499
|
|
|
$
|
196,360,196
|
|
Costs Incurred
For the years ended September 30, the Company incurred the following costs in oil and natural gas producing activities:
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
Property acquisition costs
|
|
$
|
11,409,673
|
|
|
$
|
20,190
|
|
|
$
|
-
|
|
Exploration costs
|
|
|
-
|
|
|
|
-
|
|
|
|
21,049
|
|
Development costs
|
|
|
10,291,476
|
|
|
|
25,382,377
|
|
|
|
5,075,710
|
|
|
|
$
|
21,701,149
|
|
|
$
|
25,402,567
|
|
|
$
|
5,096,759
|
|
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 unweighted arithmetic average of the first-day-of-the-month price for each month within such
(86)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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, 2018, 2017 and 2016.
The Company’s net proved oil, NGL and natural gas reserves, which are located in the contiguous United States, as of September 30, 2018, 2017 and 2016, 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 Southwestern Energy Company and Occidental Petroleum Corporation, with reservoir
(87)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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.
(88
)
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, 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
(1,407,995
|
)
|
|
|
303,728
|
|
|
|
(29,247
|
)
|
|
|
(6.7
|
)
|
Acquisitions (divestitures)
|
|
|
236,690
|
|
|
|
24,765
|
|
|
|
(1,782,949
|
)
|
|
|
(0.2
|
)
|
Extensions, discoveries and other additions
|
|
|
1,982,624
|
|
|
|
476,174
|
|
|
|
9,400,374
|
|
|
|
24.2
|
|
Production
|
|
|
(336,564
|
)
|
|
|
(255,176
|
)
|
|
|
(8,721,262
|
)
|
|
|
(12.3
|
)
|
September 30, 2018
|
|
|
5,984,422
|
|
|
|
2,934,190
|
|
|
|
120,062,036
|
|
|
|
173.6
|
|
The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2018 - $62.86/Bbl, $26.13/Bbl, $2.56/Mcf; September 30, 2017 - $46.31/Bbl, $17.55/Bbl, $2.81/Mcf; September 30, 2016 - $36.77/Bbl, $12.22/Bbl, $1.97/Mcf.
The revisions of previous estimates from 2017 to 2018 were primarily the result of:
|
•
|
Negative pricing revisions of 2.4 Bcfe, primarily resulting from gas wells currently projected to reach their projected economic limits earlier than projected in 2017 due to lower natural gas prices in 2018 relative to 2017; proved developed revisions of 1.7 Bcfe and PUD revisions of 0.7 Bcfe.
|
(89
)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
|
•
|
Negative performance revisions of 4.2 Bcfe. Proved developed revisions were positive 7.
6
Bcfe, principally due to better well performance from
high-
interest wells drilled in 2017 in the Anadarko Basin Woodford and sou
theastern Oklahoma Woodford. Proved undeveloped negative revisions of 11.
8
Bcfe are a result of a delayed Eagle Ford drilling program in 2018 which resulted in removal of wells that are no longer projected to be developed within 5 years from the date they
were added
due to unanticipated drilling delays. However, the Eagle Ford drilling program is now underway
.
|
Acquisitions and divestitures were the result of:
|
•
|
The sale of 2.8 Bcfe in marginal properties located in northwestern Oklahoma and Kearny County, Kansas.
|
|
•
|
The acquisition of 2.6 Bcfe, predominately in the active drilling program of the Bakken in North Dakota; 1.4 Bcfe proved developed and 1.2 Bcfe proved undeveloped.
|
Extensions, discoveries and other additions from 2017 to 2018 are principally attributable to:
|
•
|
Proved developed reserve extensions, discoveries and other additions of 3.7 Bcfe resulting from:
|
|
a)
|
The Company’s working and royalty interest ownership in ongoing development of unconventional oil, NGL and natural gas utilizing extended horizontal drilling in the Woodford Shale in the Anadarko Basin and southeastern Oklahoma.
|
|
b)
|
The Company’s working and royalty interest ownership in ongoing development of unconventional oil, NGL and natural gas utilizing horizontal drilling in the STACK Meramec play in the Anadarko Basin in western Oklahoma.
|
|
c)
|
The Company’s royalty interest ownership in ongoing development of conventional and unconventional oil, NGL and natural gas utilizing horizontal drilling in the Permian Basin of New Mexico and Texas.
|
|
•
|
The addition of 20.4 Bcfe of PUD reserves primarily within the Company’s active drilling program areas of 1) the Anadarko Basin Woodford Shale in western Oklahoma, 2) the Anadarko Basin STACK Meramec in western Oklahoma and 3) the current drilling program of the Eagle Ford Shale in Texas.
|
(90
)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
|
|
Proved Developed Reserves
|
|
|
Proved Undeveloped Reserves
|
|
|
|
Oil
|
|
|
NGL
|
|
|
Natural
Gas
|
|
|
Oil
|
|
|
NGL
|
|
|
Natural
Gas
|
|
|
|
(Barrels)
|
|
|
(Barrels)
|
|
|
(Mcf)
|
|
|
(Barrels)
|
|
|
(Barrels)
|
|
|
(Mcf)
|
|
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
|
|
September 30, 2018
|
|
|
2,334,587
|
|
|
|
2,085,706
|
|
|
|
83,151,954
|
|
|
|
3,649,835
|
|
|
|
848,484
|
|
|
|
36,910,082
|
|
The following details the changes in proved undeveloped reserves for 2018 (Mcfe):
Beginning proved undeveloped reserves
|
|
|
56,880,555
|
|
Proved undeveloped reserves transferred to proved developed
|
|
|
(2,158,716
|
)
|
Revisions
|
|
|
(12,456,931
|
)
|
Extensions and discoveries
|
|
|
20,413,545
|
|
Purchases
|
|
|
1,221,543
|
|
Ending proved undeveloped reserves
|
|
|
63,899,996
|
|
Beginning PUD reserves were 56.9 Bcfe. A total of 2.2 Bcfe (4% of the beginning balance) was transferred to proved developed during 2018. In the last two years, 41% of the beginning PUD reserves were transferred to proved developed. The 12.5 Bcfe (22% of the beginning balance) of negative revisions to PUD reserves were pricing revisions of 0.7 Bcfe and performance revision of 11.8 Bcfe, predominately resulting from the removal of oil, NGL and natural gas reserves associated with Eagle Ford wells that are no longer projected to be developed within 5 years from the date they were added due to a delayed drilling program in 2018. We anticipate that all the Company’s current 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 20.4 Bcfe of PUD reserves in 2018 primarily within the Company’s active drilling program areas of 1) the Anadarko Basin Woodford Shale in western Oklahoma, 2) the Anadarko Basin STACK Meramec in western Oklahoma and 3) the current drilling program of the Eagle Ford Shale in Texas. These additions result from continuing development and additional well performance data in each of the referenced plays. Of the 2018 PUD adds, 1.2 Bcfe was drilling or completing at year-end.
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
(91)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
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 quant
ities 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.
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
Future cash inflows
|
|
$
|
759,899,074
|
|
|
$
|
637,509,599
|
|
|
$
|
380,263,695
|
|
Future production costs
|
|
|
(259,413,766
|
)
|
|
|
(256,193,675
|
)
|
|
|
(182,948,045
|
)
|
Future development and asset retirement costs
|
|
|
(89,518,449
|
)
|
|
|
(93,133,683
|
)
|
|
|
(72,431,842
|
)
|
Future income tax expense
|
|
|
(95,872,182
|
)
|
|
|
(102,193,819
|
)
|
|
|
(38,674,100
|
)
|
Future net cash flows
|
|
|
315,094,677
|
|
|
|
185,988,422
|
|
|
|
86,209,708
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10% annual discount
|
|
|
(158,768,823
|
)
|
|
|
(105,155,847
|
)
|
|
|
(56,439,589
|
)
|
Standardized measure of discounted future net
cash flows
|
|
$
|
156,325,854
|
|
|
$
|
80,832,575
|
|
|
$
|
29,770,119
|
|
(92
)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
Changes in the standardized measure of discounted future net cash flows are as follows:
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
Beginning of year
|
|
$
|
80,832,575
|
|
|
$
|
29,770,119
|
|
|
$
|
81,591,211
|
|
Changes resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of oil, NGL and natural gas, net of
production costs
|
|
|
(32,836,007
|
)
|
|
|
(25,783,055
|
)
|
|
|
(16,749,632
|
)
|
Net change in sales prices and production costs
|
|
|
47,533,281
|
|
|
|
37,186,619
|
|
|
|
(86,198,778
|
)
|
Net change in future development and asset
retirement costs
|
|
|
1,580,942
|
|
|
|
(7,939,156
|
)
|
|
|
21,636,258
|
|
Extensions and discoveries
|
|
|
34,667,557
|
|
|
|
38,582,908
|
|
|
|
11,640,704
|
|
Revisions of quantity estimates
|
|
|
(8,391,223
|
)
|
|
|
15,282,587
|
|
|
|
(41,716,689
|
)
|
Acquisitions (divestitures) of reserves-in-place
|
|
|
(307,472
|
)
|
|
|
(962,667
|
)
|
|
|
-
|
|
Accretion of discount
|
|
|
12,602,209
|
|
|
|
4,789,294
|
|
|
|
14,424,032
|
|
Net change in income taxes
|
|
|
(3,057,128
|
)
|
|
|
(27,070,430
|
)
|
|
|
44,533,277
|
|
Change in timing and other, net
|
|
|
23,701,120
|
|
|
|
16,976,356
|
|
|
|
609,736
|
|
Net change
|
|
|
75,493,279
|
|
|
|
51,062,456
|
|
|
|
(51,821,092
|
)
|
End of year
|
|
$
|
156,325,854
|
|
|
$
|
80,832,575
|
|
|
$
|
29,770,119
|
|
12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following is a summary of the Company’s unaudited quarterly results of operations.
|
|
Fiscal 2018
|
|
|
|
Quarter Ended
|
|
|
|
December
31
|
|
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
Revenues
|
|
$
|
12,490,526
|
|
|
$
|
11,421,258
|
|
|
$
|
9,557,937
|
|
|
$
|
11,564,543
|
|
Income (loss) before provision for
income taxes
|
|
$
|
1,074,939
|
|
|
$
|
1,046,176
|
|
|
$
|
(984,093
|
)
|
|
$
|
759,647
|
|
Net income (loss)
|
|
$
|
13,784,939
|
|
|
$
|
1,070,176
|
|
|
$
|
(775,093
|
)
|
|
$
|
555,647
|
|
Earnings (loss) per share
|
|
$
|
0.81
|
|
|
$
|
0.06
|
|
|
$
|
(0.05
|
)
|
|
$
|
0.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
(93
)
Panhandle Oil and Gas Inc.
Notes to Financial Statements (continued)
13
.
SUBSEQUENT EVENTS
(AUDITED)
On November 30, 2018, the Company closed on a mineral acreage sale of 206 net mineral acres in Lea and Eddy Counties, New Mexico. The sale price was $9.3 million or approximately $45,000 per acre. The proceeds will initially be used to reduce the Company’s bank debt. This sale represents 0.08% of the Company’s total net mineral acreage position, 0.7% of total production and 0.9% of total revenues for fiscal year 2018. This sale also includes 1.2% of our total proved reserves as of September 30, 2018.
These minerals had no net book value at September 30, 2018,
and the total value received less any post-closing adjustments will be a gain on the sale of assets in the Company’s first quarter of 2019.
(94
)