(The accompanying notes are an integral part of these condensed financial statements.)
(The accompanying notes are an integral part of these condensed financial statements.)
(The accompanying notes are an integral part of these condensed financial statements.)
(The accompanying notes are an integral part of these condensed financial statements.)
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1: Basis of Presentation and Accounting Principles
Basis of Presentation
The accompanying unaudited condensed financial statements of PHX Minerals Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the SEC. Management believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The results are not necessarily indicative of those to be expected for the full fiscal year. The Company’s fiscal year runs from October 1 through September 30.
Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2021. Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “PHX” or “Company” refer to PHX Minerals Inc.
Recent Accounting Pronouncements
Standard
|
|
Description
|
|
Date of Adoption
|
|
Impact on Financial Statements or Other Significant Matters
|
Adoption of New Accounting Pronouncements
|
ASU 2019-12, Simplifying the Accounting for Income Taxes.
|
|
This standard is intended to clarify and simplify the accounting for income taxes by removing certain exceptions and amending existing guidance.
|
|
Q1 2022
|
|
The adoption of this update did not have a material impact on the Company's financial statements and related disclosures.
|
Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.
NOTE 2: Revenues
Lease bonus revenue
The Company generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any natural gas, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in ASC 932 (Extractive Activities—Oil and Gas), and upon leasing, it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral being treated as a gain. The excess of lease bonus above the mineral basis is shown in the lease bonuses and rental income line item on the Company’s Statements of Operations.
Natural gas and oil derivative contracts
See Note 9 for discussion of the Company’s accounting for derivative contracts.
Revenues from contracts with customers
Natural gas, oil and NGL sales
(5)
Sales of natural gas, oil and NGL are recognized when production is sold to a purchaser and control of the product has been transferred. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Company receives for natural gas and NGL is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Each unit of commodity is considered a separate performance obligation; however, as consideration is variable, the Company utilizes the variable consideration allocation exception permitted under the standard to allocate the variable consideration to the specific units of commodity to which they relate.
Disaggregation of natural gas, oil and NGL revenues
The following table presents the disaggregation of the Company's natural gas, oil and NGL revenues for the three months ended December 31, 2021 and 2020:
|
|
Three Months Ended December 31, 2021
|
|
|
|
|
Royalty Interest
|
|
|
Working Interest
|
|
|
Total
|
|
|
Natural gas revenue
|
|
$
|
5,200,868
|
|
|
$
|
3,489,167
|
|
|
$
|
8,690,035
|
|
|
Oil revenue
|
|
|
1,894,027
|
|
|
|
1,682,077
|
|
|
|
3,576,104
|
|
|
NGL revenue
|
|
|
625,623
|
|
|
|
795,402
|
|
|
|
1,421,025
|
|
|
Natural gas, oil and NGL sales
|
|
$
|
7,720,518
|
|
|
$
|
5,966,646
|
|
|
$
|
13,687,164
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, 2020
|
|
|
|
|
Royalty Interest
|
|
|
Working Interest
|
|
|
Total
|
|
|
Natural gas revenue
|
|
$
|
1,190,165
|
|
|
$
|
2,268,636
|
|
|
$
|
3,458,801
|
|
|
Oil revenue
|
|
|
1,096,952
|
|
|
|
1,244,114
|
|
|
|
2,341,066
|
|
|
NGL revenue
|
|
|
230,338
|
|
|
|
394,774
|
|
|
|
625,112
|
|
|
Natural gas, oil and NGL sales
|
|
$
|
2,517,455
|
|
|
$
|
3,907,524
|
|
|
$
|
6,424,979
|
|
|
Prior-period performance obligations and contract balances
The Company records revenue in the month production is delivered to the purchaser. As a non-operator, the Company has limited visibility into the timing of when new wells start producing, and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the natural gas, oil and NGL sales receivables line item on the Company’s balance sheets. The difference between the Company's estimates and the actual amounts received for natural gas, oil and NGL sales is recorded in the quarter that payment is received from the third party. For the three months ended December 31, 2021, revenue recognized during the reporting period related to performance obligations satisfied in prior reporting periods for existing wells was approximately $0.5 million and primarily due to change in price estimates. This is considered a change in estimate.
As noted above, as a non-operator, there are instances when the Company is limited by the information operators provide to it. Through cash received on new wells, in the 2022 first quarter, the Company identified several producing properties on its minerals that had production dates prior to the 2022 first quarter. Estimates of the natural gas and oil sales related to those properties were made and are reflected in the first quarter natural gas, oil and NGL sales on the Company’s Statements of Operations and on the Company’s balance sheets in natural gas, oil and NGL sales receivables. In connection with obtaining more relevant information on new wells on Company acreage for the three months ended December 31, 2021, the Company recorded a change in estimate for new wells to natural gas, oil and NGL sales totaling $342,361 ,of which $83,569 related to the production periods before October 1, 2020 and $258,792 related to fiscal 2021.
(6)
NOTE 3: Income Taxes
The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from excess federal and Oklahoma percentage depletion, which are permanent tax benefits, and the change in valuation allowance from prior year. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that exceeds cost depletion, which is calculated on a unit-of-production basis. The Company completes an evaluation of the expected realization of the Company’s gross deferred tax assets each quarter. Excess tax benefits and deficiencies of stock-based compensation are recognized as provision (benefit) for income taxes in the Company’s Statements of Operations.
Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with detailed well-by-well calculations at fiscal year-end. Depending upon whether a provision for income taxes or a benefit for income taxes is expected for a year, Federal and Oklahoma excess percentage depletion will either decrease or increase the effective tax rate, respectively. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock-based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant.
As of December 31, 2021, the Company completed an evaluation of the expected realization of its gross deferred tax assets. Due to reversal of deferred tax assets in the current period, the Company is in a net deferred tax liability position as of December 31, 2021. The Company expects to realize its gross deferred tax assets against reversing deferred tax liabilities in future periods. Therefore, in the current period the Company released the valuation allowance against deferred tax assets. The Company continues to maintain a valuation allowance against certain state net operating loss carryforwards that are not expected to be utilized. The Company’s effective tax rate for the three months ended December 31, 2021 was a 10% provision as compared to a 10% benefit for the three months ended December 31, 2020.
The federal Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The CARES Act provides relief to corporate taxpayers by permitting a five-year carryback of 2018-2020 Net Operating Losses (“NOLs”), removing the 80% limitation on the carryback of those NOLs, increasing the limitation on interest expense deductibility under Section 163(j) of the Internal Revenue Code (“IRC”), from 30% to 50% of adjusted taxable income for 2019 and 2020, and accelerates refunds for minimum tax credit carryforwards, along with a few other provisions. On July 28, 2020, final regulations were issued under Section 163(j) of the IRC, which modified the calculation under the previous proposed regulations of adjusted taxable income for purposes of the 50% limitation on interest expense. Under the final regulations, depreciation, amortization, and depletion capitalizable under Section 263A of the IRC is added back to tentative taxable income. This change allowed all interest expense to be deductible for 2020 and reduced the associated deferred tax asset to zero. During the quarter ended March 31, 2021, the Company received a tax refund totaling $1.4 million associated with the alternative minimum tax (AMT) credits, which was accelerated by the CARES Act. During the quarter ended December 31, 2021, the Company received $2.2 million associated with the carryback of the Company’s 2020 federal net operating loss.
NOTE 4: Basic and Diluted Earnings (Loss) Per Common Share (“EPS”)
Basic and diluted earnings (loss) per share of Common Stock is calculated using net income (loss) divided by the weighted average number of voting shares of Common Stock outstanding, including unissued, vested directors’ deferred compensation shares, during the period.
For the three months ended December 31, 2021, the Company did not include restricted stock in the diluted EPS calculation because the effect would have been antidilutive. The average shares outstanding of restricted stock excluded from the diluted EPS was 73,208 and 81,663 for the three months ended December 31, 2021 and 2020, respectively.
(7)
The following table presents a reconciliation of the components of basic and diluted EPS.
|
Three Months Ended December 31,
|
|
|
2021
|
|
|
2020
|
|
Basic EPS
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
Basic net income (loss)
|
$
|
6,682,249
|
|
|
$
|
(596,720
|
)
|
Denominator:
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
33,127,722
|
|
|
|
22,556,236
|
|
Basic EPS
|
$
|
0.20
|
|
|
$
|
(0.03
|
)
|
|
|
|
|
|
|
|
|
Diluted EPS
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
Basic net income (loss)
|
$
|
6,682,249
|
|
|
$
|
(596,720
|
)
|
Diluted net income (loss)
|
|
6,682,249
|
|
|
|
(596,720
|
)
|
Denominator:
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
33,127,722
|
|
|
|
22,556,236
|
|
Effects of dilutive securities:
|
|
|
|
|
|
|
|
Unvested restricted stock
|
|
-
|
|
|
|
-
|
|
Diluted weighted average shares outstanding
|
|
33,127,722
|
|
|
|
22,556,236
|
|
Diluted EPS
|
$
|
0.20
|
|
|
$
|
(0.03
|
)
|
NOTE 5: Long-Term Debt
The Company has a $100,000,000 credit facility (the “Credit Facility”) with a syndicate of banks led by Independent Bank pursuant to a credit agreement entered into in September 2021 (as amended, the “Credit Agreement”). The Credit Facility has a current borrowing base of $32,000,000 as of December 31, 2021, and a maturity date of September 1, 2025. The Credit Facility is secured by the Company’s personal property and at least 80% of the total value of the proved, developed and producing oil and gas properties. The interest rate is based on either (a) LIBOR plus an applicable margin ranging from 2.750% to 3.750% per annum based on the Company’s Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for such day, or (2) the overnight cost of federal funds as announced by the U.S. Federal Reserve System in effect on such day plus one-half of one percent (0.50%), plus, in each case, an applicable margin ranging from 1.750% to 2.750% per annum based on the Company’s Borrowing Base Utilization. The election of Independent Bank prime or LIBOR is at the Company’s discretion. The interest rate spread from Independent Bank prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At December 31, 2021, the effective interest rate was 3.75%.
The Company’s debt is recorded at the carrying amount on its balance sheets. The carrying amount of the debt under the Credit Facility approximates fair value because the interest rates are reflective of market rates. Debt issuance costs associated with the Credit Facility are presented in “Other, net” on the Company’s balance sheets. Total debt issuance cost, net of amortization, as of December 31, 2021 was $288,247. The debt issuance cost is amortized over the life of the Credit Facility.
Determinations of the borrowing base under the Credit Facility are made semi-annually (usually June and December) or whenever the lending banks, in their sole discretion, believe that there has been a material change in the value of the Company’s natural gas and oil properties. The Credit Facility contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain restrictions on the Company’s ability to incur debt, grant liens, make fundamental changes and engage in certain transactions with affiliates. The Credit Facility also restricts the Company’s ability to make certain restricted payments if before or after the Restricted Payment (i) the Available Commitment is less than ten percent (10%) of the Borrowing Base or (ii) the Leverage Ratio on a pro forma basis is greater than 2.50 to 1.00. In addition, the Company is required to maintain certain financial ratios, a current ratio (as described in the Credit Facility) of no less than 1.0 to 1.0 and a funded debt to EBITDAX (as defined in the Credit Facility) of no more than 3.5 to 1.0 based on the trailing twelve months. At December 31, 2021, the Company was in compliance with the covenants of the Credit Facility and had $20,000,000 in outstanding borrowings and had $12,000,000 available for borrowing under the Credit Facility. All capitalized terms in this description of the Credit Facility that are not otherwise defined in this Form 10-Q shall have the meaning assigned to them in the Credit Agreement.
(8)
NOTE 6: Deferred Compensation Plan for Non-Employee Directors
Annually, non-employee directors may elect to be included in the Deferred Compensation Plan for Non-Employee Directors. This plan provides that each outside director may individually elect to be credited with future unissued shares of Company Common Stock rather than cash for all or a portion of their annual retainers and Board and committee meeting fees. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares on the payment dates of the annual retainers. Only upon a director’s retirement, termination or death or a change-in-control of the Company will the shares recorded for such director be issued under this plan. Directors may elect to receive shares, when issued, over annual time periods of up to ten years. The promise to issue such shares in the future is an unsecured obligation of the Company.
NOTE 7: Restricted Stock Plan
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 three months ended December 31, 2021 and 2020 related to the Company’s market-based, time-based and performance-based restricted stock:
|
|
Three Months Ended
|
|
|
|
December 31,
|
|
|
|
2021
|
|
|
2020
|
|
Market-based, restricted stock
|
|
$
|
77,482
|
|
|
$
|
10,247
|
|
Time-based, restricted stock
|
|
|
178,362
|
|
|
|
112,731
|
|
Performance-based, restricted stock
|
|
|
-
|
|
|
|
-
|
|
Total compensation expense
|
|
$
|
255,844
|
|
|
$
|
122,978
|
|
A summary of the Company’s unrecognized compensation cost for its unvested market-based, time-based and performance-based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized is shown in the following table:
|
|
As of December 31, 2021
|
|
|
|
Unrecognized Compensation Cost
|
|
|
Weighted Average Period (in years)
|
|
Market-based, restricted stock
|
|
$
|
569,027
|
|
|
|
1.97
|
|
Time-based, restricted stock
|
|
|
194,601
|
|
|
|
0.96
|
|
Performance-based, restricted stock
|
|
|
-
|
|
|
|
|
|
Total
|
|
$
|
763,628
|
|
|
|
|
|
NOTE 8: Properties and Equipment
Properties and equipment and related accumulated DD&A as of December 31, 2021 and September 30, 2021 are as follows:
|
|
December 31, 2021
|
|
|
September 30, 2021
|
|
Properties and equipment at cost, based on successful efforts accounting:
|
|
|
|
|
|
|
|
|
Producing natural gas and oil properties
|
|
$
|
249,861,777
|
|
|
$
|
319,984,874
|
|
Non-producing natural gas and oil properties
|
|
|
54,960,073
|
|
|
|
40,466,098
|
|
Other property and equipment
|
|
|
883,310
|
|
|
|
794,179
|
|
|
|
|
305,705,160
|
|
|
|
361,245,151
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(195,971,382
|
)
|
|
|
(257,643,661
|
)
|
Net properties and equipment
|
|
$
|
109,733,778
|
|
|
$
|
103,601,490
|
|
(9)
Acquisitions
Quarter Ended
|
|
Net royalty acres (1)(2)
|
|
|
Purchase Price (1)
|
|
Area of Interest
|
December 31, 2021
|
|
|
|
|
|
|
|
|
|
|
|
426
|
|
|
$5.8 million
|
|
Haynesville / LA
|
|
|
|
847
|
|
|
$4.1 million
|
|
Haynesville / LA
|
|
|
|
172
|
|
|
$1.4 million
|
|
SCOOP / OK
|
|
|
|
103
|
|
|
$0.6 million
|
|
Haynesville / TX
|
|
|
|
116
|
|
|
$1.7 million
|
|
Haynesville / LA
|
|
|
|
220
|
|
|
$1.2 million
|
|
SCOOP / OK
|
December 31, 2020
|
|
|
|
|
|
|
|
|
|
|
|
142
|
|
|
$1.0 million
|
|
Haynesville / TX
|
|
|
|
184
|
|
|
$0.8 million
|
|
Haynesville / TX
|
|
|
|
386
|
|
|
$3.5 million
|
|
Haynesville / TX
|
|
|
|
297
|
|
|
$2.3 million
|
|
SCOOP / OK
|
(1) Excludes subsequent closing adjustments and insignificant acquisitions.
|
(2) An estimated net royalty equivalent was used for the minerals included in the net royalty acres.
|
All purchases made in 2021 and 2022 were for mineral and royalty acreage and were accounted for as asset acquisitions.
Divestitures
The Company divested approximately 700 working interest wellbores during the three months ended December 31, 2021, which resulted in reductions to producing natural gas and oil properties of approximately $71.1 million, accumulated depreciation, depletion and amortization of approximately $63.6 million, asset retirement obligation of approximately $0.7 million, and a loss on sale of assets of approximately $2.2 million. The net proceeds from these divestitures was approximately $4.6 million.
Quarter Ended
|
|
Wellbores(1)
|
|
Sale Price
|
|
Gain/(Loss)
|
|
Location
|
December 31, 2021
|
|
|
|
|
|
|
|
|
|
|
98 wellbores
|
|
$2.0 million
|
|
($3.5) million
|
|
OK
|
|
|
95 wellbores
|
|
$0.5 million
|
|
$0.2 million
|
|
OK / TX
|
|
|
499 wellbores
|
|
$2.1 million
|
|
$1.1 million
|
|
AR
|
December 31, 2020
|
|
|
|
|
|
|
|
|
|
|
No significant divestitures
|
|
|
|
|
|
|
(1) Number of Wellbores associated with working interests sold.
|
|
|
Natural Gas, Oil and NGL Reserves
Management considers the estimation of the Company’s natural gas, oil and NGL reserves to be the most significant of its judgments and estimates. Changes in natural gas, oil and NGL reserve estimates affect the Company’s calculation of DD&A, provision for retirement of assets and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s independent consulting petroleum engineer, with assistance from Company staff, prepares estimates of natural gas, oil and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geologic and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing appropriate prices for the current period. The estimated natural gas, oil and NGL reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month natural gas, oil and NGL price for each month within the 12-month period prior to the balance sheet date, held flat over the life of the properties. However, projected future natural gas, oil and NGL pricing assumptions are used by management to prepare estimates of natural gas, oil and NGL reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions. Natural gas, oil and NGL prices are volatile, affected by worldwide production and consumption, and are outside the control of management.
Impairment
Company management monitors all long-lived assets, principally natural gas and oil properties, for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as inflation rates; future drilling and completion costs; future sales prices for natural gas, oil and NGL; future production costs; estimates of future natural gas, oil and NGL reserves to be recovered and the timing thereof; the economic and regulatory climates; and other factors. The need to test a
(10)
property for impairment may result from significant declines in sales prices or unfavorable adjustments to natural gas, oil and NGL reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations to reflect any material changes since the prior report was issued and then utilizes updated projected future price decks current with the period. For the three months ended December 31, 2021 and 2020, management’s assessment resulted in no impairment provisions on producing properties. The Company wrote off $5,585 on wells assigned with zero consideration received during the three months ended December 31, 2021.
NOTE 9: Derivatives
The Company has entered into commodity price derivative agreements, including fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of natural gas and oil. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. These contracts cover only a portion of the Company’s natural gas and oil production and provide only partial price protection against declines in natural gas and oil prices. The Company’s derivative contracts are currently with BP Energy Company (“BP”). The derivative contracts with BP are secured under the Credit Facility with Independent Bank (see Note 5: Long-Term Debt). The derivative instruments have settled or will settle based on the prices below:
Derivative contracts in place as of December 31, 2021
|
|
|
|
|
|
|
Fiscal Period
|
|
Contract total volume
|
|
Index
|
|
Contract average price
|
Natural gas costless collars
|
|
|
|
|
|
|
Remaining 2022
|
|
610,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.50 floor / $4.19 ceiling
|
2023
|
|
500,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.32 floor / $4.54 ceiling
|
2024
|
|
60,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.00 floor / $4.70 ceiling
|
Natural gas fixed price swaps
|
|
|
|
|
|
|
Remaining 2022
|
|
2,818,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.94
|
2023
|
|
1,980,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.22
|
2024
|
|
360,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.40
|
Oil fixed price swaps
|
|
|
|
|
|
|
Remaining 2022
|
|
113,000 Bbls
|
|
NYMEX WTI
|
|
$44.25
|
2023
|
|
43,500 Bbls
|
|
NYMEX WTI
|
|
$52.84
|
2024
|
|
4,500 Bbls
|
|
NYMEX WTI
|
|
$67.55
|
The Company has elected not to complete all of the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net liability of $6,545,877 as of December 31, 2021, and a net liability of $13,784,467 as of September 30, 2021. Cash receipts or payments in the following table reflect the gain or loss on derivative contracts which settled during the respective periods, and the non-cash gain or loss reflect the change in fair value of derivative contracts as of the end of the respective periods:
(11)
|
Three Months Ended
|
|
|
December 31,
|
|
|
2021
|
|
|
2020
|
|
Cash received (paid) on derivative contracts:
|
|
|
|
|
|
|
|
Natural gas costless collars
|
$
|
-
|
|
|
$
|
(8,967
|
)
|
Natural gas fixed price swaps(1)
|
|
(1,352,192
|
)
|
|
|
(1,863
|
)
|
Oil costless collars
|
|
-
|
|
|
|
88,944
|
|
Oil fixed price swaps(1)
|
|
(362,139
|
)
|
|
|
535,200
|
|
Cash received (paid) on derivative contracts, net
|
$
|
(1,714,331
|
)
|
|
$
|
613,314
|
|
Non-cash gain (loss) on derivative contracts:
|
|
|
|
|
|
|
|
Natural gas costless collars
|
$
|
79,971
|
|
|
$
|
678,961
|
|
Natural gas fixed price swaps
|
|
4,477,934
|
|
|
|
288,887
|
|
Oil costless collars
|
|
-
|
|
|
|
(410,886
|
)
|
Oil fixed price swaps
|
|
(7,406
|
)
|
|
|
(1,424,312
|
)
|
Non-cash gain (loss) on derivative contracts, net
|
$
|
4,550,499
|
|
|
$
|
(867,350
|
)
|
Gains (losses) on derivative contracts, net
|
$
|
2,836,168
|
|
|
$
|
(254,036
|
)
|
|
|
(1) Excludes $2,688,091 of cash paid to settle off-market derivative contracts that are not reflected on the 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 of whether or not to offset, 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 Company’s 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 December 31, 2021 and September 30, 2021. The Company has offset all amounts subject to master netting agreements in the Company's balance sheets at December 31, 2021 and September 30, 2021.
|
|
December 31, 2021
|
|
|
September 30, 2021
|
|
|
|
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 Liabilities
|
|
Gross amounts recognized
|
|
$
|
386,069
|
|
|
$
|
6,799,377
|
|
|
$
|
364,782
|
|
|
$
|
497,351
|
|
|
$
|
17,395
|
|
|
$
|
12,105,383
|
|
|
$
|
1,696,479
|
|
Offsetting adjustments
|
|
|
(386,069
|
)
|
|
|
(386,069
|
)
|
|
|
(364,782
|
)
|
|
|
(364,782
|
)
|
|
|
(17,395
|
)
|
|
|
(17,395
|
)
|
|
|
-
|
|
Net presentation on condensed balance sheets
|
|
$
|
-
|
|
|
$
|
6,413,308
|
|
|
$
|
-
|
|
|
$
|
132,569
|
|
|
$
|
-
|
|
|
$
|
12,087,988
|
|
|
$
|
1,696,479
|
|
(a) See Note 10: Fair Value Measurements for further disclosures regarding fair value of financial instruments.
The fair value of derivative assets and derivative liabilities is adjusted for credit risk. The impact of credit risk was immaterial for all periods presented.
NOTE 10: 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
(12)
observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability.
The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis at December 31, 2021:
|
|
Fair Value Measurement at December 31, 2021
|
|
|
|
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
|
|
$
|
-
|
|
|
$
|
(6,625,848
|
)
|
|
$
|
-
|
|
|
$
|
(6,625,848
|
)
|
Derivative Contracts - Collars
|
|
$
|
-
|
|
|
$
|
79,971
|
|
|
$
|
-
|
|
|
$
|
79,971
|
|
Level 2 – Market Approach - The fair values of the Company’s swaps and collars are based on a third-party pricing model, which utilizes inputs that are either readily available in the public market, such as natural gas curves and volatility curves, or can be corroborated from active markets. These values are based upon future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.
The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy:
|
|
Quarter Ended December 31,
|
|
|
|
2021
|
|
|
2020
|
|
|
|
Fair Value
|
|
|
Impairment
|
|
|
Fair Value
|
|
|
Impairment
|
|
Producing Properties (a)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
(a) When indicators of impairment are present, the Company assesses the carrying value of its natural gas and oil properties for impairment. This assessment utilizes estimates of future cash flows as well as other market data. Significant judgments and assumptions in these assessments include estimates of future natural gas, oil and NGL 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 values in excess of their calculated fair values.
At December 31, 2021 and September 30, 2021, 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, the valuation of which is classified as Level 2 as the carrying amount of the Company’s debt under the 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.
NOTE 11: Commitments and Contingencies
Litigation
The Company may be the subject of threatened or pending legal actions and contingencies in the normal course of conducting our business. The Company provides for costs related to these matters when a loss is probable and the amount can be reasonably estimated. The effect of the outcome of these matters on our future results of operations and liquidity cannot be predicted because any such effect depends on future results of operations and the amount or timing of the resolution of such matters. For certain types of claims, the Company maintains insurance coverage for personal injury and property damage, product liability and other liability coverages in amounts and with deductibles that it believes are prudent, but there can be no assurance that these coverages will be applicable or adequate to cover adverse outcomes of claims or legal proceedings against the Company.
(13)
NOTE 12: Subsequent Events
Derivative Contracts
Subsequent to December 31, 2021, the Company entered into new derivative contracts as summarized in the table below:
|
|
Contract
|
|
|
|
|
Contract period
|
|
total volume
|
|
Index
|
|
Contract price
|
Oil fixed price swaps
|
|
|
|
|
|
|
January - December 2023
|
|
9,000 Bbls
|
|
NYMEX WTI
|
|
$70.05
|
Acquisitions
Subsequent to December 31, 2021, the Company purchased 267 net royalty acres for $2.5 million and sold 7,201 net mineral acres for $2.1 million.