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 2016 Annual Report on Form 10-K.
Adoption of New Accounting Pronouncements
In April 2015, the FASB issued Accounting Standards Update (“ASU”) 2015-03,
Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs
. The update requires that debt issuance costs related to a recognized debt liability
, such as senior notes, term loans and note payables,
be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with the presentation of debt discounts.
Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset
. The recognition and measurement guidance for debt issuance costs is not affected by the update. For public entities, the guidance is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years.
In August 2015, the FASB issued ASU 2015-15,
Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements
, which allows for line-of-credit arrangements to be handled consistently with the presentation of debt issuance costs prior to ASU 2015-03 issued in April 2015. For public entities, the guidance is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years.
The Company adopted ASU 2015-03 and ASU 2015-15 as of December 31, 2016. The Company elected to continue to show debt issuance costs associated with its credit facility (Company’s only debt) as assets versus a direct reduction of the debt liability. Therefore, the adoption had no impact on the Company's current and previously reported balance sheets, shareholders' equity, results of operations, or cash flows. In accordance with ASU 2015-15, unamortized debt issuance costs associated with the Company's credit facility, which amounted to $202,938 and $263,584 as of March 31, 2017, and September 30, 2016, respectively, remain reflected in "Other property and equipment" on the balance sheets.
In November 2015, the FASB issued ASU 2015-17,
Balance Sheet Classification of Deferred Taxes
. The update requires that deferred income tax assets and liabilities be classified as noncurrent in the balance sheet. For public entities, the guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years.
The Company early adopted ASU 2015-17 as of December 31, 2016, on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $310,900 as of September 30, 2016, from "Deferred income taxes" in current assets to “Deferred income tax, net” in long term liabilities on the balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2015-17.
In August 2016, the FASB issued ASU 2016-15,
Classification of Certain Cash Receipts and Cash Payments
, which addresses certain issues where diversity in practice was identified and may change how an entity classifies certain cash receipts and cash payments on its statement of cash flows. The new guidance also clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. This guidance will generally be applied retrospectively and is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption is permitted. All of the amendments in ASU 2016-15 are required to be adopted at the same time.
(5)
The Company early adopted ASU 2016-15 as of Decem
ber 31, 2016.
As a result of the adoption, the Company reclassified
“Proceeds from leasing fee mineral acreage”
, which totaled $
3,191,075
and $
3,193,775
for the six months ended
March 31, 2017, and March 31, 2016
, res
pectively, from Investing Activities to
Operating Activities on the Condensed Statements of Cash Flows as these transactions are made in our normal course of business and represent operating activities based on the application of the predominance principle. As another result of this adoption, w
e are also electing to classify our distributions received from equity method investments using the Cumulative Earnings Approach.
Distributions received are considered returns on investment and classified as cash inflows from operating activities, unless t
he investor’s cumulative distributions received less distributions received in prior periods that were determined to be returns of investment exceed cumulative equity in earnings recognized by the investor. When such an excess occurs, the current-period di
stribution up to this excess should be considered a return of investment and classified as cash inflows from investing activities. This election did not have any impact on our cash flow statements as the Company was already applying this approach.
Adoption
of ASU
2016-15
had no impact on the Company's current and previously reported shareholders' equity, results of operations or
balance sheets
. The affected prior period balances in the Condensed Statements of Cash Flows presented throughout this report on F
orm 10-Q have been adjusted to reflect the ret
roactive adoption of ASU 2016-15
.
In March 2016, the FASB issued ASU 2016-09,
Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting
. The new guidance is intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. The guidance
changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows.
The standard is effective for interim and annual reporting periods beginning after December 15, 2016, and will be adopted either prospectively, retrospectively or using a modified retrospective transition approach depending on the topic covered in the standard.
Early adoption is permitted for any organization in any interim or annual period.
On a prospective basis companies will no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies will be recognized as income tax expense or benefit in the income statement. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. Also, companies will have to present excess tax benefits and deficiencies as operating activities on the statement of cash flows (prospectively or retrospectively).
The new guidance will also require an employer to classify as a financing activity in its statement of cash flows the cash paid to a tax authority when shares are withheld to satisfy the employer’s statutory income tax withholding obligation.
The Company early adopted ASU 2016-09 as of October 1, 2016. As a result of the adoption, the Company recorded $228,000 of excess tax benefits from stock-based compensation in the “Provision (benefit) for income taxes” on the Condensed Statements of Operations in the current period versus “Capital in excess of par” on the Condensed Balance Sheets as was previously required. This part of the guidance is to be applied prospectively, so the prior period balances have not been reclassified. The Company also presented excess tax benefits from stock-based compensation in the “Operating Activities” section of the Condensed Statements of Cash Flows in the current period versus the “Financing Activities” section of the Condensed Statements of Cash Flows as was previously presented. The Company has elected to apply this part of the guidance prospectively, so the prior period balances have not been reclassified. The guidance also requires that companies present employees taxes paid upon vesting as financing activities on the statement of cash flows (Purchases of Treasury Stock). This requirement had no impact on the Company, as this has been the practice historically. The Company is also electing to account for forfeitures of awards as they occur, instead of estimating a forfeiture amount. A cumulative-effect adjustment to retained earnings was not necessary for this transition as there were no material forfeitures estimated or incurred in the past. The adoption of this ASU could cause volatility in the effective tax rate going forward.
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. For public entities, the guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this update will have on our financial statements.
(6)
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 mea
surement of financial instruments. The new guidance is effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. We are assessing the potential impact that this update will have
on our financial statements.
In May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers
, which will supersede nearly all existing revenue recognition guidance under GAAP. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We are evaluating our existing revenue recognition policies to determine whether any contracts in the scope of the guidance will be affected by the new requirements. The standard is effective for us on October 1, 2018. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements. We are currently evaluating the potential impact that this update will have on our financial statements and the transition method that will be elected.
Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.
NOTE 2: Income Taxes
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. The adoption of ASU 2016-09 will also increase volatility in the effective tax rate going forward.
Excess tax benefits and deficiencies of stock based compensation will be recognized as income tax expense (benefit) in the statement of operations prospectively versus additional paid in capital in the equity section of the balance sheet as was previously required.
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 proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the six months ended March 31, 2017, was a 33% benefit as compared to a 40% benefit for the six months ended March 31, 2016. The effective tax rate for the quarter ended March 31, 2017, was a 19% provision as compared to a 38% benefit for the quarter ended March 31, 2016.
NOTE 3: 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 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, 2018. The credit facility is subject to a semi-annual borrowing base determination, wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The facility is secured by certain of the Company’s properties with a net book value of $158,317,717 at March 31, 2017. The interest rate is based on BOK prime plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At March 31, 2017, the effective interest rate was 2.98%.
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.
(7)
Determinations of the borrowing base are made semi-annually (June and December) or whenever the banks, in their discre
tion, believe that there has been a material change in the value of the oil and natural gas properties. In December 2016, the borrowing base was redetermined by the banks and left unchanged at $80,000,000. The loan agreement contains customary covenants wh
ich, 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. In addition, the Company is required to maintain
certain financial ratios, a current ratio (as defined – 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) of no more than 4.0 to 1.0. At March
31, 2017, the Company was in compliance with the covenants of the loan agreement and has $36,000,000 of availability under its outstanding credit facility.
NOTE 5: 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 6: 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 retain, attract 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 pursuant to the Company’s Amended 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.
On December 9, 2016, the Company awarded 6,845 non-performance based shares and 20,531 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. The non-performance and performance based shares had a fair value on their award date of $176,260 and $292,884, respectively. The fair value for the performance and the non-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 9, 2016, through December 9, 2019).
On December 31, 2016, the Company awarded 8,916 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, 2017. The restricted stock contains non-forfeitable rights to receive dividends and voting rights during the vesting period. These non-performance based shares had a fair value on their award date of $209,970.
(8)
The foll
owing table summarizes the Company’s pre-tax compensation expense for the three and six months ended March 31, 2017 and 2016, related to the Company’s performance based and non-performance based restricted stock.
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
March 31,
|
|
|
March 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
Performance based, restricted stock
|
|
$
|
51,302
|
|
|
$
|
40,380
|
|
|
$
|
130,518
|
|
|
$
|
309,890
|
|
Non-performance based, restricted stock
|
|
|
85,919
|
|
|
|
96,308
|
|
|
|
187,115
|
|
|
|
198,205
|
|
Total compensation expense
|
|
$
|
137,221
|
|
|
$
|
136,688
|
|
|
$
|
317,633
|
|
|
$
|
508,095
|
|
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 March 31, 2017
|
|
|
|
Unrecognized Compensation Cost
|
|
|
Weighted Average Period (in years)
|
|
Performance based, restricted stock
|
|
$
|
370,222
|
|
|
|
2.17
|
|
Non-performance based, restricted stock
|
|
|
403,166
|
|
|
|
1.64
|
|
Total
|
|
$
|
773,388
|
|
|
|
|
|
Upon vesting, shares are expected to be issued out of shares held in treasury.
NOTE 7: 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 geological 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. 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.
NOTE 8: 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 the three months ended March 31, 2017 and 2016, the assessment resulted in impairment provisions on producing properties of $10,788 and $8,115,791, respectively. For the six months ended March 31, 2017 and 2016, the assessment resulted in impairment provisions on producing properties of $10,788 and $11,849,064, respectively. 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.
(9)
NOTE 9: Capitalized Costs
As of March 31, 2017, and September 30, 2016, non-producing oil and natural gas properties include costs of $0 and $5,917, respectively, on exploratory wells which were drilling and/or testing.
NOTE 10: 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. All of the Company’s derivative contracts are 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.
Derivative contracts in place as of March 31, 2017
|
|
Production volume
|
|
|
|
|
Contract period
|
|
covered per month
|
|
Index
|
|
Contract price
|
Natural gas costless collars
|
|
|
|
|
|
|
January - June 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.85 floor / $3.35 ceiling
|
January - December 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.80 floor / $3.47 ceiling
|
January - December 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.00 floor / $3.35 ceiling
|
April - December 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.80 floor / $3.35 ceiling
|
April - December 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.75 floor / $3.35 ceiling
|
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
|
Natural gas fixed price swaps
|
|
|
|
|
|
|
November 2016 - April 2017
|
|
80,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.955
|
January - December 2017
|
|
25,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.100
|
April - December 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.070
|
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
|
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
|
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
|
Oil fixed price swaps
|
|
|
|
|
|
|
January - December 2017
|
|
3,000 Bbls
|
|
NYMEX WTI
|
|
$53.89
|
April - June 2017
|
|
5,000 Bbls
|
|
NYMEX WTI
|
|
$53.50
|
April - December 2017
|
|
2,000 Bbls
|
|
NYMEX WTI
|
|
$54.20
|
(10)
Derivative contracts in place as of September 30,
2016
|
|
Production volume
|
|
|
|
|
Contract period
|
|
covered per month
|
|
Index
|
|
Contract price
|
Natural gas costless collars
|
|
|
|
|
|
|
April - October 2016
|
|
200,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$1.95 floor / $2.40 ceiling
|
October - December 2016
|
|
70,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.75 floor / $3.05 ceiling
|
October - December 2016
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.90 floor / $3.40 ceiling
|
November 2016 - March 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.25 floor / $3.65 ceiling
|
November 2016 - March 2017
|
|
80,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.25 floor / $3.95 ceiling
|
November 2016 - March 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.60 floor / $3.25 ceiling
|
January - June 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.85 floor / $3.35 ceiling
|
January - December 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.80 floor / $3.47 ceiling
|
January - December 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.00 floor / $3.35 ceiling
|
April - December 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.80 floor / $3.35 ceiling
|
April - December 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.75 floor / $3.35 ceiling
|
Natural gas fixed price swaps
|
|
|
|
|
|
|
October 2016
|
|
100,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.410
|
October 2016 - March 2017
|
|
25,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.200
|
November 2016 - April 2017
|
|
80,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$2.955
|
January - December 2017
|
|
25,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.100
|
April - December 2017
|
|
50,000 Mmbtu
|
|
NYMEX Henry Hub
|
|
$3.070
|
Oil costless collars
|
|
|
|
|
|
|
July - December 2016
|
|
3,000 Bbls
|
|
NYMEX WTI
|
|
$35.00 floor / $49.00 ceiling
|
October - December 2016
|
|
3,000 Bbls
|
|
NYMEX WTI
|
|
$40.00 floor / $47.25 ceiling
|
October 2016 - March 2017
|
|
3,000 Bbls
|
|
NYMEX WTI
|
|
$40.00 floor / $58.50 ceiling
|
October 2016 - March 2017
|
|
3,000 Bbls
|
|
NYMEX WTI
|
|
$45.00 floor / $54.00 ceiling
|
October 2016 - March 2017
|
|
3,000 Bbls
|
|
NYMEX WTI
|
|
$45.00 floor / $55.50 ceiling
|
The Company has elected not to complete 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 $43,705 as of March 31, 2017, and a net liability of $428,271 as of September 30, 2016.
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 March 31, 2017, and September 30, 2016. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at March 31, 2017, and September 30, 2016.
|
|
March 31, 2017
|
|
|
September 30, 2016
|
|
|
|
Fair Value (a)
|
|
|
Fair Value (a)
|
|
|
|
Commodity Contracts
|
|
|
Commodity Contracts
|
|
|
|
Current Assets
|
|
|
Current Liabilities
|
|
|
Current Assets
|
|
|
Current Liabilities
|
|
|
Non-Current Assets
|
|
|
Non-Current Liabilities
|
|
Gross amounts recognized
|
|
$
|
516,889
|
|
|
$
|
560,594
|
|
|
$
|
68,235
|
|
|
$
|
471,847
|
|
|
$
|
4,759
|
|
|
$
|
29,418
|
|
Offsetting adjustments
|
|
|
(516,889
|
)
|
|
|
(516,889
|
)
|
|
|
(68,235
|
)
|
|
|
(68,235
|
)
|
|
|
(4,759
|
)
|
|
|
(4,759
|
)
|
Net presentation on Condensed Balance Sheets
|
|
$
|
-
|
|
|
$
|
43,705
|
|
|
$
|
-
|
|
|
$
|
403,612
|
|
|
$
|
-
|
|
|
$
|
24,659
|
|
(11)
(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 11: 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 March 31, 2017.
|
|
Fair Value Measurement at March 31, 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
|
|
$
|
-
|
|
|
$
|
33,605
|
|
|
$
|
-
|
|
|
$
|
33,605
|
|
Derivative Contracts - Collars
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(77,310
|
)
|
|
$
|
(77,310
|
)
|
Level 2 – Market Approach - The fair values of the Company’s swaps are based on a third-party pricing model which utilizes inputs that are either readily available in the public market, such as natural gas curves, or can be corroborated from active markets. These values are based upon future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.
Level 3 – The fair values of the Company’s costless collar contracts are based on a pricing model which utilizes inputs that are unobservable or not readily available in the public market. These values are based upon future prices, volatility, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.
The significant unobservable inputs for Level 3 derivative contracts include market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of our derivative contracts. An increase (decrease) in the volatility of oil and natural gas prices will decrease (increase) the fair value of oil and natural gas derivatives and adverse changes to our counterparties’ creditworthiness will decrease the fair value of our derivatives.
The following table represents quantitative disclosures about unobservable inputs for Level 3 Fair Value Measurements.
Instrument Type
|
|
Unobservable Input
|
|
Range
|
|
Weighted Average
|
|
|
Fair Value
March 31, 2017
|
|
Oil Collars
|
|
Oil price volatility curve
|
|
0% - 24.17%
|
|
|
15.91%
|
|
|
$
|
129,053
|
|
Natural Gas Collars
|
|
Gas price volatility curve
|
|
0% - 37.76%
|
|
|
21.04%
|
|
|
$
|
(206,363
|
)
|
(12)
A reconciliation of the Company’s derivative contracts classified as Level 3
measurements is presented below. All gains and losses are presented on the Gains (losses) on derivative contracts line item on our Condensed Statements of Operations.
|
|
Derivatives
|
|
Balance of Level 3 as of October 1, 2016
|
|
$
|
(316,658
|
)
|
Total gains or (losses)
|
|
|
|
|
Included in earnings
|
|
|
486,421
|
|
Included in other comprehensive income (loss)
|
|
|
-
|
|
Purchases, issuances and settlements
|
|
|
(247,073
|
)
|
Transfers in and out of Level 3
|
|
|
-
|
|
Balance of Level 3 as of March 31, 2017
|
|
$
|
(77,310
|
)
|
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 March 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
Fair Value
|
|
|
Impairment
|
|
|
Fair Value
|
|
|
Impairment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing Properties (a)
|
|
$
|
7,868
|
|
|
$
|
10,788
|
|
|
$
|
6,589,196
|
|
|
$
|
8,115,791
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
Fair Value
|
|
|
Impairment
|
|
|
Fair Value
|
|
|
Impairment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing Properties (a)
|
|
$
|
7,868
|
|
|
$
|
10,788
|
|
|
$
|
9,741,650
|
|
|
$
|
11,849,064
|
|
(a) At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil and natural gas prices using a forward NYMEX curve adjusted for 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 March 31, 2017, and September 30, 2016, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which the valuation is classified as Level 3 and is based on a valuation technique that requires inputs that are both unobservable and significant to the overall fair value measurement. The fair value measurement of our long-term debt is valued using a discounted cash flow model that calculates the present value of future cash flows pursuant to the terms of the debt agreements and applies estimated current market interest rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.