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Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) (Tables)
 12 Months Ended
Jun. 30, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Schedule of costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities
The following table summarizes costs incurred and capitalized in oil and natural gas property related to acquisition, exploration and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling. Exploration and development costs also include amounts incurred due to the recognition of asset retirement obligations of $471,864, $140,151 and $576,039 during the years ended June 30, 2017, 2016, and 2015, respectively.
 
For the Years Ended June 30,
 
2017
 
2016
 
2015
Oil and Natural Gas Activities
 
 
 
 
 
Property acquisition costs:
 
 
 
 
 
Proved property
$
—

 
$
—

 
$
—

Unproved property (a)
—

 
596,500

 
—

Exploration costs
—

 
—

 
—

Development costs
7,554,579

 
19,093,200

 
10,975,637

Total costs incurred for oil and natural gas activities
$
7,554,579

 
$
19,689,700

 
$
10,975,637


(a) As described in Note 17 — Delhi Field Litigation Settlement, we received a 23.9% working interest in the non-producing Mengel Interval with an estimated fair value of $596,500. This cost is included in properties subject to amortization.
Schedule of estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves for each of the periods indicated were as follows:
 
Crude Oil
(Bbls)
 
Natural Gas
Liquids
(Bbls)
 
Natural Gas
(Mcf)
 
BOE
Proved developed and undeveloped reserves:
 
 
 
 
 
 
 
June 30, 2014
10,526,344

 
2,278,688

 
2,906,863

 
13,289,510

Revisions of previous estimates (a)
(64,074
)
 
156,195

 
(2,894,703
)
 
(390,330
)
Improved recovery, extensions and discoveries
—

 
—

 
—

 
—

Sales of minerals in place
—

 
—

 
—

 
—

Production (sales volumes)
(450,294
)
 
(1,288
)
 
(7,221
)
 
(452,786
)
June 30, 2015
10,011,976

 
2,433,595

 
4,939

 
12,446,394

Revisions of previous estimates (b)
(765,385
)
 
(198,233
)
 
(3,319
)
 
(964,171
)
Improved recovery, extensions and discoveries
—

 
—

 
—

 
—

Sales of minerals in place
—

 
—

 
—

 
—

Production (sales volumes)
(658,041
)
 
(491
)
 
(1,620
)
 
(658,802
)
June 30, 2016
8,588,550

 
2,234,871

 
—

 
10,823,421

Revisions of previous estimates (c)
508,123

 
(504,733
)
 
16

 
3,390

Improved recovery, extensions and discoveries
—

 
—

 
—

 
—

Sales of minerals in place
—

 
—

 
—

 
—

Production (sales volumes)
(724,523
)
 
(43,907
)
 
(16
)
 
(768,433
)
June 30, 2017
8,372,150

 
1,686,231

 
—

 
10,058,378

Proved developed reserves:
 
 
 
 
 
 
 
June 30, 2014
7,858,224

 
32,164

 
481,042

 
7,970,562

June 30, 2015
7,347,231

 
1,572

 
4,939

 
7,349,626

June 30, 2016
7,168,249

 
—

 
—

 
7,168,249

June 30, 2017
6,617,389

 
1,332,803

 
—

 
7,950,192

Proved undeveloped reserves:
 
 
 
 
 
 
 
June 30, 2014
2,668,120

 
2,246,524

 
2,425,821

 
5,318,948

June 30, 2015
2,664,745

 
2,432,023

 
—

 
5,096,768

June 30, 2016
1,420,301

 
2,234,871

 
—

 
3,655,172

June 30, 2017
1,754,761

 
353,425

 
—

 
2,108,186





(a) The 2,894,703 revision for natural gas in fiscal 2015 primarily reflects a 2,246,524 MCF reduction for the Delhi field NGL plant together with a 452,786 MCF revision at the Giddings Field for a well that was lost due to mechanical issues. The NGL plant revision resulted from a decision to change in the plant design to use the methane production internally to reduce field operating costs rather than selling it into the market. The 156,195 BBL positive natural gas liquids revision primarily reflects 185,499 BBL positive revision for better recovery from the redesigned NGL plant, partly offset by a 29,304 BBL negative revision from the lost Giddings well.

(b) The negative revision results primarily from the removal of proved undeveloped reserves in the far eastern part of the Delhi field, referred to as Test Site 6, which were deemed uneconomic under the lower SEC price case utilized at the end of the period.

(c) The positive crude oil revision resulted from better production performance during fiscal 2017 and the expectation of greater ultimate recoveries of oil from the Delhi field. The negative NGL revision results primarily from lower expectations for ultimate NGL recoveries from the plant based on production data after the plant commenced production.

Schedule of standardized measure of discounted future net cash flows related to proved oil and natural gas reserves
The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2017, 2016, and 2015 are as follows:
 
For the Years Ended June 30,
 
2017
 
2016
 
2015
Future cash inflows
$
425,094,736

 
$
383,491,193

 
$
807,030,282

Future production costs and severance taxes
(213,115,443
)
 
(179,182,565
)
 
(309,225,333
)
Future development costs
(22,631,856
)
 
(16,595,047
)
 
(49,691,006
)
Future income tax expenses
(47,055,551
)
 
(45,713,438
)
 
(123,888,665
)
Future net cash flows
142,291,886

 
142,000,143

 
324,225,278

10% annual discount for estimated timing of cash flows
(59,354,333
)
 
(64,042,824
)
 
(165,028,739
)
Standardized measure of discounted future net cash flows
$
82,937,553

 
$
77,957,319

 
$
159,196,539
Schedule of NYMEX prices used in determining future cash flows
Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12 months unweighted arithmetic average first-day-of-the-month commodity prices for each year and reflect adjustments for lease quality, transportation fees, energy content and regional price differentials.
 
Year Ended June 30,
 
2017
 
2016
 
2015
 
Oil
(Bbl)
 
Gas
(MMBtu)
 
Oil
(Bbl)
 
Gas
(MMBtu)
 
Oil
(Bbl)
 
Gas
(MMBtu)
NYMEX prices used in determining future cash flows
$
48.85

 
n/a
 
$
42.91

 
n/a
 
$
71.88

 
$
3.44
Schedule of changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves is as follows:
 
For the Years Ended June 30,
 
2017
 
2016
 
2015
Balance, beginning of year
$
77,957,319

 
$
159,196,539

 
$
226,077,672

Net changes in sales prices and production costs related to future production
19,821,288

 
(120,832,747
)
 
(88,043,095
)
Changes in estimated future development costs
(1,626,833
)
 
74,991

 
(9,585,405
)
Sales of oil and gas produced during the period, net of production costs
(23,649,087
)
 
(17,079,363
)
 
(18,538,016
)
Net change due to extensions, discoveries, and improved recovery
—

 
—

 
—

Net change due to revisions in quantity estimates
(2,206,287
)
 
(18,821,014
)
 
(9,391,321
)
Net change due to sales of minerals in place
—

 
—

 
—

Development costs incurred during the period
2,632,547

 
16,327,883

 
7,785,095

Accretion of discount
10,086,904

 
21,870,650

 
31,974,540

Net change in discounted income taxes
(5,045,279
)
 
36,598,239

 
34,157,767

Net changes in timing of production and other
4,966,981

 
622,141

 
(15,240,698
)
Balance, end of year
$
82,937,553

 
$
77,957,319

 
$
159,196,539