NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1: Basis of Presentation and Accounting Principles
Basis of Presentation
The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the SEC. Management of the Company believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The results are not necessarily indicative of those to be expected for the full year. The Company’s fiscal year runs from October 1 through September 30.
Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s 2018 Annual Report on Form 10-K.
Certain amounts (loss (gain) on asset sales and other in the Statements of Operations) in the prior years have been reclassified to conform to the current year presentation.
Adoption of New Accounting Pronouncements
Revenue recognition and presentation – In May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09,
Revenue from Contracts with Customers (Topic 606)
, which supersedes nearly all previously existing revenue recognition guidance under U.S. GAAP. Subsequently, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08,
Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net).
This new guidance became effective for reporting periods beginning after December 15, 2017. The Company adopted the new revenue recognition and presentation guidance on October 1, 2018, as required. See Note 2: Revenues for discussion of the adoption impact and the applicable disclosures required by the new guidance.
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 pursuant to an optional election) 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 changed 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, but the Company has chosen not to early adopt. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are assessing the potential impact that this standard 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.
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.
(5
)
NOTE 2:
Revenues
Adoption of new revenue recognition and disclosure guidance
In May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers (Topic 606)
,
which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition.
Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08,
Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net),
pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer.
The Company adopted the new revenue recognition and presentation guidance on October 1, 2018. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements 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. The Company chose to use the modified retrospective method upon adoption and has applied the guidance only to contracts that are not complete at the date of initial application.
Adoption of the new guidance had no cumulative effect impact on the Company's retained earnings at October 1, 2018.
The standard did not have a material effect on the timing or measurement of the Company's revenue recognition or its financial position, results of operations, net income and cash flows. Additionally, the application of ASU 2016-08’s gross versus net presentation guidance did not impact the Company’s presentation of revenues and expenses.
As the Company’s interests in oil and natural gas properties are non-operated interests or royalty interests, the Company evaluated its agreements with operators in connection with the ASC 606 principal versus agent indicators. Consistent with previous conclusions under ASC 605, the Company concluded that the operators act as an agent in the transfer of commodities to third party customers. This determination required judgment in the application of the guidance for principal versus agent under ASC 606.
Revenues from Contracts with Customers
Oil, NGL and natural gas sales
Sales of oil, NGL and natural gas are recognized at the point in time that control of the product is transferred to the customer and collectability of the sales price is reasonably assured. 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.
Lease bonus income
The Company also earns revenue from lease bonuses. 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 oil, NGL or natural gas discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received.
The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in ASC 932, and it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral being treated as 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.
Oil and natural gas derivative contracts –
See Note 9 for discussion of the Company’s accounting for derivative contracts.
(6
)
Disaggregation of oil, NGL and natural gas revenues
The following table presents the disaggregation of the Company's oil, NGL and natural gas revenues for the three months ended December 31, 2018.
|
|
Three Months Ended
|
|
|
|
December 31, 2018
|
|
Oil revenue
|
|
$
|
4,478,980
|
|
NGL revenue
|
|
|
1,454,835
|
|
Natural gas revenue
|
|
|
6,276,904
|
|
Oil, NGL and natural gas sales
|
|
$
|
12,210,719
|
|
Performance obligations
The Company satisfies the performance obligations under its oil and natural gas sales contracts upon delivery of its production and related transfer of title to purchasers. Upon delivery of production, the Company has a right to receive consideration from its purchasers in amounts that correspond with the value of the production transferred.
Allocation of transaction price to remaining performance obligations
Oil, NGL and natural gas sales
As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has utilized the practical expedient in ASC 606 which permits the Company
to allocate variable consideration to one or more but not all performance obligations in the contract if the terms of the variable payment relate specifically to the Company’s efforts to satisfy that performance obligation and allocating the variable amount to the performance obligation is consistent with the allocation objective under ASC 606. Additionally, the Company will not disclose variable consideration subject to this practical expedient
.
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 Oil, NGL and natural gas sales receivables line item in the accompanying balance sheets. The difference between the Company's estimates and the actual amounts received for oil, NGL and natural gas sales is recorded in the quarter that payment is received from the third party. For the three months ended December 31, 2018, and December 31, 2017, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods was immaterial and considered a change in estimate.
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. 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. Excess tax benefits and deficiencies of stock-based compensation are recognized as income tax expense (benefit) in the statement 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. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock-based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the
(7)
proportional effect of these items on the effective tax rate may be significant.
The effective tax rate for the quarter ended
December 31, 2
018
, was a
22%
provision
as compared to a
1182%
benefit
for the quarter ended
December 31, 2017
.
NOTE 4: Basic and Diluted Earnings (Loss) per Share
Basic and diluted earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of voting common shares outstanding, including unissued, vested directors’ deferred compensation shares during the period.
NOTE 5: Long-term Debt
The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a current borrowing base of $80,000,000 and a maturity date of November 30, 2022. The credit facility is subject to a semi-annual borrowing base determination, wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The facility is secured by certain of the Company’s properties (wellbore only) with a net book value of $133,361,948 at December 31, 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 balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as the ratio of loan balance to the borrowing base increases. At December 31, 2018, the effective interest rate was 4.63%.
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 discretion, believe that there has been a material change in the value of the oil and natural gas properties. On January 3, 2019, the borrowing base was redetermined by the banks and left unchanged at $80,000,000. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined by the bank agreement – current assets includes availability under outstanding credit facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (trailing twelve months as defined by the 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 December 31, 2018, the Company was in compliance with the covenants of the loan agreement and has $38,500,000 of availability under its outstanding credit facility.
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. The Deferred Compensation Plan for Non-Employee Directors provides that each outside director may individually elect to be credited with future unissued shares of Company common stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers. Only upon a director’s retirement, termination, death, or a change-in-control of the Company will the shares recorded for such director be issued under the Deferred Compensation Plan for Non-Employee Directors. Directors may elect to receive shares, when issued, over annual time periods 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
In March 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 200,000 shares of common stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. In March 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, as amended, is designed to provide as much flexibility as possible for future grants of restricted stock so that the Company can respond as necessary to provide competitive compensation in order to attract, retain and motivate directors and officers of the Company and to align their interests with those of the Company’s shareholders.
Effective in May 2014, the board of directors adopted resolutions to allow management, at their discretion, to purchase the Company’s common stock as treasury shares up to an amount equal to the aggregate number of shares of common stock awarded
(8)
pursuant to the Company’s Am
ended 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.
Effective in May 2018, the board of directors approved an amendment to the Company’s existing stock repurchase program. As amended, the Repurchase Program will continue to allow the Company to repurchase up to $1.5 million of the Company’s common stock at management’s discretion. The Board added language to clarify that this is intended to be an evergreen program as the repurchase of an additional $1.5 million of the Company’s common stock is authorized and approved whenever the previous amount is utilized. In addition, 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.
On December 11, 2018, the Company awarded 12,044 non-performance based shares and 36,131 performance based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of a three-year period and contains non-forfeitable rights to receive dividends and voting rights during the vesting period. Upon vesting, the performance based shares that do not meet the performance criteria are forfeited. The non-performance and performance based shares had a fair value on their award date of $189,332 and $297,621, respectively. The fair value for the non-performance and the performance based awards will be recognized as compensation expense ratably over the vesting period. The fair value of the performance based shares on their award date is calculated by simulating the Company’s stock prices as compared to the Dow Jones Select Oil Exploration and Production Index (DJSOEP) prices utilizing a Monte Carlo model covering the performance period (December 11, 2018, through December 11, 2021).
On December 31, 2018, the Company awarded 11,290 non-performance based shares of the Company’s common stock as restricted stock to its non-employee directors. The restricted stock vests quarterly over one year starting on March 31, 2019. The restricted stock contains non-forfeitable rights to receive dividends and to vote the shares during the vesting period. These non-performance based shares had a fair value on their award date of $174,995.
The following table summarizes the Company’s pre-tax compensation expense for the three months ended December 31, 2018 and 2017, related to the Company’s performance based and non-performance based restricted stock.
|
|
Three Months Ended
|
|
|
|
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
Performance based, restricted stock
|
|
$
|
63,537
|
|
|
$
|
96,665
|
|
Non-performance based, restricted stock
|
|
|
95,932
|
|
|
|
97,385
|
|
Total compensation expense
|
|
$
|
159,469
|
|
|
$
|
194,050
|
|
A summary of the Company’s unrecognized compensation cost for its unvested performance based and non-performance based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.
|
|
As of December 31, 2018
|
|
|
|
Unrecognized Compensation Cost
|
|
|
Weighted Average Period (in years)
|
|
Performance based, restricted stock
|
|
$
|
555,473
|
|
|
|
2.29
|
|
Non-performance based, restricted stock
|
|
|
543,061
|
|
|
|
1.86
|
|
Total
|
|
$
|
1,098,534
|
|
|
|
|
|
NOTE 8: Properties and Equipment
Divestitures
During the first quarter of 2019, the Company sold 206 net mineral acres and producing oil and gas properties, primarily located in Lea and Eddy Counties, New Mexico, to a private buyer for total net consideration of $9,096,938 and recorded a gain on the sale of $9,096,938. The cash from the sale was used to reduce the Company’s outstanding bank debt.
(9
)
Acquisitions
During the first quarter of 2019, the Company acquired 45 net mineral acres (which include producing oil and gas properties) in the STACK play in Blaine County, Oklahoma, with undeveloped locations identified in both the Woodford and Meramac Shales for $423,000.
Oil, NGL and Natural Gas Reserves
Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, provision for retirement of assets and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil, NGL and natural gas reserves based on available 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 oil, NGL and natural gas reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil, NGL and natural gas price for each month within the 12-month period prior to the balance sheet date, held flat over the life of the properties. However, projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions. Crude oil, NGL and natural gas prices are volatile and affected by worldwide production and consumption and are outside the control of management.
Impairment
All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as: inflation rates; future drilling and completion costs; future sales prices for oil, NGL and natural gas; future production costs; estimates of future oil, NGL and natural gas reserves to be recovered and the timing thereof; the economic and regulatory climates and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations to reflect any material changes since the prior report was issued and then utilizes updated projected future price decks current with the period. For both the three months ended December 31, 2018 and 2017, the assessment resulted in no impairment provisions on producing properties. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company.
(10
)
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 oil and natural gas. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. These contracts cover only a portion of the Company’s natural gas and oil production and provide only partial price protection against declines in natural gas and oil prices. These derivative instruments may expose the Company to risk of financial loss and limit the benefit of future increases in prices. The Company’s derivative contracts are currently with Bank of Oklahoma and Koch Supply and Trading LP. The derivative contracts with Bank of Oklahoma are secured under its credit facility with Bank of Oklahoma. The derivative contracts with Koch are unsecured. The derivative instruments have settled or will settle based on the prices below.
Derivative contracts in place as of December 31, 2018
|
|
Production volume
|
|
|
|
|
Contract period
|
|
covered per month
|
|
Index
|
|
Contract price
|
Natural gas fixed price swaps
|
|
|
|
|
|
|
July 2018 - March 2019
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.065
|
January - March 2019
|
|
100,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.460
|
January - June 2019
|
|
150,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.981
|
January - June 2019
|
|
100,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.310
|
January - June 2019
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.303
|
January - July 2019
|
|
100,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.867
|
Oil costless collars
|
|
|
|
|
|
|
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
|
July 2019- June 2020
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$65.00 floor / $76.15 ceiling
|
January - June 2020
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$60.00 floor / $67.00 ceiling
|
Oil fixed price swaps
|
|
|
|
|
|
|
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
|
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 asset of $2,792,165 as of December 31, 2018, and a net liability of $3,414,016 as of September 30, 2018. Net cash paid related to derivative contracts settled during the three-month period ended December 31, 2018, was $1,699,401 compared to net cash received of $357,184 in the same period in the prior year.
The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Balance Sheets.
The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's Condensed Balance Sheets at December 31, 2018, and September 30, 2018. The Company
(11)
has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at
December 31, 2018
, and
September 30, 2018
.
|
|
December 31, 2018
|
|
|
September 30, 2018
|
|
|
|
Fair Value (a)
|
|
|
Fair Value (a)
|
|
|
|
Commodity Contracts
|
|
|
Commodity Contracts
|
|
|
|
Current Assets
|
|
|
Current Liabilities
|
|
|
Non-Current Assets
|
|
|
Current Assets
|
|
|
Current Liabilities
|
|
|
Non-Current Liabilities
|
|
Gross amounts recognized
|
|
$
|
2,502,245
|
|
|
$
|
32,617
|
|
|
$
|
322,537
|
|
|
$
|
42,150
|
|
|
$
|
3,106,196
|
|
|
$
|
349,970
|
|
Offsetting adjustments
|
|
|
(32,617
|
)
|
|
|
(32,617
|
)
|
|
|
-
|
|
|
|
(42,150
|
)
|
|
|
(42,150
|
)
|
|
|
-
|
|
Net presentation on Condensed Balance Sheets
|
|
$
|
2,469,628
|
|
|
$
|
-
|
|
|
$
|
322,537
|
|
|
$
|
-
|
|
|
$
|
3,064,046
|
|
|
$
|
349,970
|
|
(a) See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.
The fair value of derivative assets and derivative liabilities is adjusted for credit risk. The impact of credit risk was immaterial for all periods presented.
NOTE 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 observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability.
The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2018.
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Fair Value Measurement at December 31, 2018
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|
|
|
Quoted Prices in Active Markets
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|
|
Significant Other Observable Inputs
|
|
|
Significant Unobservable Inputs
|
|
|
Total Fair
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Value
|
|
Financial Assets (Liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Contracts - Swaps
|
|
$
|
-
|
|
|
$
|
1,558,346
|
|
|
$
|
-
|
|
|
$
|
1,558,346
|
|
Derivative Contracts - Collars
|
|
$
|
-
|
|
|
$
|
1,233,819
|
|
|
$
|
-
|
|
|
$
|
1,233,819
|
|
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.
At December 31, 2018, and September 30, 2018,
the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short-term maturities of those instruments.
Financial instruments include long-term debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.
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