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16. Oil and Gas Reserve Data (Unaudited)
 12 Months Ended
Mar. 31, 2015
Extractive Industries [Abstract]  
Oil and Gas Reserve Data (Unaudited)

16. Oil and Gas Reserve Data (Unaudited)

  

The estimates of the Company’s proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance with the guidelines established by the SEC. The estimates as of March 31, 2015, 2014, and 2013 are based on evaluations prepared by Joe C. Neal and Associates, Petroleum Consultants. Management emphasizes that reserve estimates are inherently imprecise and are expected to change as new information becomes available and as economic conditions in the industry change.

 

Proved reserves are estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

  

Changes in Proved Reserves:

 

  Oil
 (Bbls)		  Natural Gas
  (Mcf)
Proved Developed and Undeveloped Reserves:          
As of April 1, 2012   346,000    8,445,000 
Revision of previous estimates   (10,000)   (589,000)
Purchase of minerals in place   48,000    71,000 
Extensions and discoveries   5,000    318,000 
Sales of minerals in place   —      —   
Production   (23,000)   (401,000)
As of March 31, 2013   366,000    7,844,000 
Revision of previous estimates   12,000    (1,404,000)
Purchase of minerals in place   50,000    18,000 
Extensions and discoveries   101,000    163,000 
Sales of minerals in place   —      —   
Production   (27,000)   (362,000)
As of March 31, 2014   502,000    6,259,000 
Revision of previous estimates   (90,000)   (665,000)
Purchase of minerals in place   43,000    795,000 
Extensions and discoveries   235,000    269,000 
Sales of minerals in place   —      —   
Production   (30,000)   (369,000)
As of March 31, 2015   660,000    6,289,000 

 

Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves ("PUD") are proved reserves are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The downward revision of oil and natural gas is primarily the result of SEC rules which require such reserves to be developed within five years and because of the participation in one unsuccessful well. Reserves written off due to the five year limitation are in the El Cinco field which are on leases held by production and are still in place to be developed in the future.

 

Summary of Proved Developed and Undeveloped Reserves as of March 31, 2015, 2014 and 2013:

 

   Oil
 (Bbls)		  Natural Gas
  (Mcf)
Proved Developed Reserves:      
As of April 1, 2012   194,620    5,359,670 
As of March 31, 2013   237,420    4,807,020 
As of March 31, 2014   294,620    4,081,470 
As of March 31, 2015   283,670    4,584,790 
           
Proved Undeveloped Reserves:          
As of April 1, 2012   151,730    3,085,060 
As of March 31, 2013   128,290    3,037,180 
As of March 31, 2014   206,930    2,177,810 
As of March 31, 2015   376,070    1,703,790 

 

As of March 31, 2015, 2014 and 2013 reserves were computed using the 12-month unweighted average of the first-day-of-the-month prices, in accordance with current SEC rules.

  

At March 31, 2015, the Company reported estimated PUDs of 3.96 bcfe, which accounted for 39% of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 73 new wells (2.7 bcfe), 6 of which we operate, and 1 new zone behind pipe from a currently producing wellbore (.4 bcfe) that the Company also operates. The Company’s timetable for this well is totally dependent on the life of the currently producing zone. After the current zone has depleted, the Company will open the new productive zone. Of the 6 wells the Company operates (1.6 bcfe), 4 wells will be drilled on existing acreage in the Goldsmith field where the Company currently operates 3 wells. The Company projects 5 operated wells will be drilled in fiscal 2016, with the 1 remaining well in fiscal 2017. Regarding the remaining 67 PUD locations operated by others (1.1 bcfe), 12 wells are currently being drilled and 2 locations are currently being prepared to drill with plans for 18 wells to follow in 2016, 27 wells in 2017, 7 wells in 2018 and 1 well in 2019.

  

The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2015.

  

Progress of Converting Proved Undeveloped Reserves:

           
    Oil & Natural Gas (Mcfe)    Future Develepment Costs 
PUDs, beginning of year   3,419,362   $4,620,320 
Revision of previous estimates   (943,113)   (441,475)
Conversions to PD reserves   (214,890)   (643,429)
Additional PUDs added   1,698,873    3,081,986 
PUDs, end of year   3,960,232   $6,617,402 

 

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2015, 2014 and 2013 along with estimates of the operating costs, production taxes and future development costs necessary to produce such reserves. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.

  

Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs including abandonment costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company’s share of proved undeveloped properties through March 31, 2020 are $6,617,402.

 

Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards.

 

The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.

  

The current reporting rules require that year end reserve calculations and future cash inflows be based on the 12-month average market prices for sales of oil and gas on the first calendar day of each month during the fiscal year discounted at 10% per year and assuming continuation of existing economic conditions. The average prices used for fiscal 2015 were $74.84 per bbl of oil and $3.595 per mcf of natural gas. The average prices used for fiscal 2014 were $94.23 per bbl of oil and $3.67 per mcf of natural gas. The average prices used for fiscal 2013 were $85.53 per bbl of oil and $2.76 per mcf of natural gas.

 

The standardized measure of discounted future net cash flows were computed by applying 12-month average prices for oil and gas (with consideration of price changes only to the extent provided by contractual arrangements in existence at year end) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on the year end statutory tax rates with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10%.

  

The basis for this table is the reserve studies prepared by an independent petroleum engineering consultant, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of proved oil and gas properties.

  

The standardized measure of discounted future cash flows at March 31, 2015, 2014 and 2013, which represents the present value of estimated future cash flows using a discount rate of 10% a year, follows:

  

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:

  

   March 31
   2015  2014  2013
Future cash inflows  $72,238,000   $70,252,000   $52,900,000 
Future production costs and taxes   (19,569,000)   (20,647,000)   (14,893,000)
Future development costs   (6,617,000)   (4,826,000)   (4,850,000)
Future income taxes   (9,254,000)   (9,801,000)   (6,374,000)
Future net cash flows   36,798,000    34,978,000    26,783,000 
Annual 10% discount for estimated timing of cash flows   (17,860,000)   (15,649,000)   (12,414,000)
Standardized measure of discounted future net cash flows  $18,938,000   $19,329,000   $14,369,000 

 

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:

  

   March 31
   2015  2014  2013
Sales of oil and gas produced, net of production costs  $(2,036,000)  $(2,762,000)  $(1,982,000)
Net changes in price and production costs   (4,066,000)   2,464,000    (5,881,000)
Changes in previously estimated development costs   2,627,000    270,000    1,150,000 
Revisions of quantity estimates   (3,718,000)   (657,000)   (811,000)
Net change due to purchases and sales of minerals in place   2,777,000    1,332,000    1,471,000 
Extensions and discoveries, less related costs   4,607,000    3,802,000    321,000 
Net change in income taxes   654,000    (1,997,000)   2,178,000 
Accretion of discount   2,474,000    1,779,000    2,495,000 
Changes in timing of estimated cash flows and other   (3,710,000)   729,000    (3,928,000)
Changes in standardized measure   (391,000)   4,960,000    (4,987,000)
Standardized measure, beginning of year   19,329,000    14,369,000    19,356,000 
Standardized measure, end of year  $18,938,000   $19,329,000   $14,369,000