| Oil and Gas Properties Policy [Policy Text Block] | Note 16. Supplemental Oil and Gas Disclosures (Unaudited) Costs Incurred
2016
2015
Development costs
$
283,750
$
369,198
Total costs incurred
$
283,750
$
369,198 Capitalized Costs
2016
2015
Proved properties
$
7,243,509
$
7,004,779
Total oil and gas properties
7,243,509
7,004,779
Accumulated DD&A
(997,986
)
(873,027
)
Net oil and gas properties
$
6,245,523
$
6,131,752 Proved Oil and Gas Reserve
·
Future revenues were based on an un-weighted 12-month average of the first-day-of-the-month price held constant throughout the life of the properties.
·
Production and development costs were computed using year-end costs assuming no change in present economic conditions.
·
Future net cash flows were discounted at an annual rate of 10%. Reserve estimates are inherently imprecise and these estimates are expected to change as future information becomes available. Basis of Presentation As of July 31, 2016, we had twenty-two wells drilled with sixteen producing and six wells shut-in awaiting workovers. The proved reserves as of July 31, 2016 represent the reserves that were estimated to be recovered from twenty-two current wells. There are also nine wells planned for future drilling. All direct offset well locations in this report are proved undeveloped and are based on 10-acre drainage patterns unless current developed completions are estimated to drain an area larger than their volumetric assignment. In this case, the reserves of certain offset locations have been reduced. All locations have a scheduled Queens and/or Grayburg reservoir completion and each of these reservoir completions includes the cost of drilling a single wellbore. All reserves included in this report were estimated using either historical performance or volumetric methods. Estimated Quantities of Net Proved Oil and Natural Gas Reserves
2016
2015
Natural
Natural
Oil (1)
Gas (1)
Oil (1)
Gas (1)
Reserves:
Beginning of year
357,290
1,312,500
274,750
1,055,550
Revisions of previous estimates
(85,884
)
(90,208
)
15,023
122,743
Extensions, discoveries and other additions
172,970
648,460
79,984
185,834
Production
(7,396
)
(21,492
)
(12,467
)
(51,627
)
End of year
436,980
1,849,260
357,290
1,312,500 (1) Oil reserves are stated in barrels; gas reserves are stated in thousand cubic feet. The downward revision of previous gas reserves estimates was primarily due to reassessment of reservoir mapping based on additional log analysis from drilling. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves – In reviewing the information that follows, we believe that the following factors should be taken into account:
·
future costs and sales prices will probably differ from those required to be used in these calculations;
·
actual production rates for future periods may vary significantly from the rates assumed in the calculations;
·
a 10% discount rate may not be reasonable relative to risk inherent in realizing future net oil and gas revenues; and
·
future net revenues may be subject to different rates of income taxation. Under the standardized measure, future cash inflows were estimated by applying year-end oil and gas prices applicable to our reserves to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of open hedge positions. Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate and year- end prices and costs are required by ASC 932-235. In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible outcomes. Basis of Presentation Standardized Measure of Discounted Future Net Cash Flows –
2016
2015
Future cash inflows
$
19,551,030
$
24,859,110
Future production costs
(7,569,270
)
(5,929,190
)
Future development costs
(2,193,800
)
(1,361,600
)
Future income tax expense
(3,425,783
)
(6,148,912
)
Discount at 10% for estimated timing of cash flows
(1,733,300
)
(3,569,707
)
Standardized measure of discounted future net cash flows
$
4,628,877
$
7,849,701 The following table presents a reconciliation of changes in the standardized measure of discounted future net cash flows:
Years Ended July 31,
2016
2015
Standardized Measure, beginning of year
$
7,849,707
$
7,760,844
Sales of oil produced, net of production costs
279,026
(97,244
)
Net changes in prices, development and production costs
(7,500,569
)
(1,394,949
)
Extensions, discoveries and improved recovery, less related costs
3,381,367
2,047,764
Development costs incurred and changes during the period
76,471
369,198
Revisions of previous quantity estimates
(1,166,679
)
(6,394,510
)
Accretion of discount
776,341
7,079,423
Net changes in production rates and other
(1,002,119
)
161,173
Net changes in income taxes
1,935,332
(1,681,992
)
Standardized Measure, end of year
$
4,628,877
$
7,849,707 |
