Annual report pursuant to Section 13 and 15(d)

Supplemental Oil and Gas Information

v2.4.0.8
Supplemental Oil and Gas Information
 12 Months Ended
Jun. 30, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Supplementary Oil and Gas Information
Note 16 - Supplemental Oil and Gas Information (Unaudited)
Supplemental Oil and Gas Reserve Information
The Company relies upon a combination of internal technical staff and third party consulting arrangements for reserve estimation and review. The reserve information presented below is based on estimates of net proved reserves as of June 30, 2013, and 2012, and was prepared in accordance with guidelines established by the SEC.
In the US, reserve estimates were prepared by the Company's Operations Manager, Blaine Spies, for the fiscal years ended June 30, 2013, and 2012, and were audited by the Company's independent petroleum engineering firm, Allen & Crouch Petroleum Engineers ("A&C"), for the same reporting periods. A copy of the summary reserve audit report of A&C is provided as Exhibit 99.1 to this Annual Report on Form 10-K. A&C does not own an interest in any of Magellan's oil and gas properties and is not employed by Magellan on a contingent basis.
In Australia, reserve estimates were prepared by the Ryder Scott Company ("RS"), an independent petroleum engineering firm, for the fiscal years ended June 30, 2013, and 2012. Reserve estimates were prepared in accordance with the Company's internal control procedures, which include the verification of input data used by RS, and management review and approval. A copy of the summary reserve report of RS is provided as Exhibit 99.2 to this Annual Report on Form 10-K. RS does not own an interest in any of Magellan's oil and gas properties and is not employed by Magellan on a contingent basis.
Proved reserves are the estimated quantities of oil, gas, and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. All of the Company's estimated proved reserves are located in the US and Australia.

Analysis of Changes in Proved Reserves
The following table sets forth information regarding the Company's estimated proved oil and gas reserve quantities. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
 
United States
Australia (1)
 
Total
 
Oil
(Mbbls)
 
Gas
(Bcf)
 
Oil
(Mbbls)
 
Gas
(Bcf)
Proved Reserves:
 
 
 
 
 
 
 
Fiscal year beginning balance
9,190.0

 
0.4

 
9,190.0

 
0.4

Extensions and discoveries
186.4

 
—

 
186.4

 
—

Revision of previous estimates
(1,643.8
)
 
6.0

 
(1,643.8
)
 
6.0

Purchase of minerals in place
1,246.8

 
5.5

 
1,246.8

 
5.5

Production
(74.2
)
 
(0.4
)
 
(74.2
)
 
(0.4
)
Fiscal year ended June 30, 2012
8,905.2

 
11.5

 
8,905.2

 
11.5

Revision of previous estimates
(1,215.7
)
 
0.2

 
(1,215.7
)
 
0.2

Production
(320.9
)
 
(0.3
)
 
(320.9
)
 
(0.3
)
Fiscal year ended June 30, 2013
7,368.6

 
11.4

 
7,368.6

 
11.4

 
 
 
 
 
 
 
 
Proved Developed Reserves:
 
 
 
 
 
 
 
Fiscal year ended June 30, 2012
1,646.7

 
11.5

 
1,646.7

 
11.5

Fiscal year ended June 30, 2013
1,581.5

 
11.4

 
1,581.5

 
11.4

 
 
 
 
 
 
 
 
Proved Undeveloped Reserves:
 
 
 
 
 
 
 
Fiscal year ended June 30, 2012
7,258.4

 
—

 
7,258.4

 
—

Fiscal year ended June 30, 2013
5,787.2

 
—

 
5,787.2

 
—

(1) The amount of proved reserves applicable to Australia gas reflects the amount of gas committed to specific long term supply contracts.
Extensions and discoveries. Extensions and discoveries are additions to reserve amounts either by drilling a well to extend the limits of a known reservoir or by drilling a well in a reservoir that was not included in previous reserve estimates, respectively. During the year ended June 30, 2012, in the US, there was one discovery well, EPU 117, drilled in the Amsden formation at Poplar, which added 186 Mbbls to our reserves total.
Revision of previous estimates. Revisions of estimates represent upward (downward) changes in previous estimates attributable to new information gained primarily from development activity, production history, and changes to the economic conditions present at the time of each estimate. During the year ended June 30, 2013, in the US, there was a 1,216 Mbbls downward revision of estimates related to the removal from the reserves projections of four PUD wells to be drilled during calendar year 2015. These wells were removed because the Company determined it would be beneficial to use only one as opposed to two drilling rigs for its PUD drilling program, and, as a result, it would not be feasible to drill these four wells within the projected time frame. During the year ended June 30, 2013, in Australia, there were immaterial revisions of estimates related to minor variances in projections relative to the prior year. During the year ended June 30, 2012, in the US, there was a 1,644 Mbbls downward revision of estimates as a result of modifications to projected production profiles from new wells. During the same period in Australia, there was a 6.0 Bcf upward revision of gas estimates related to the signing of a new gas sales contract with Santos in May 2012.
Purchase of minerals in place. During the year ended June 30, 2012, in the US, there were 1,247 Mbbls of purchases of minerals in place related to the Company's consolidation of its ownership in NP and Poplar in September 2011. During the same period in Australia, there were 5.5 Bcf of purchases of minerals in place related to the consolidation of Magellan's ownership in Palm Valley as part of the Santos SA in the Amadeus Basin completed in May 2012. These minerals in place have been recorded as proved reserves because they have been contracted for sale under the Palm Valley GSPA.
Sales of minerals in place. There were no adjustments to reserves quantities relating to sales of minerals in place for the years ended June 30, 2013, and 2012.

Standardized Measure of Oil and Gas
The Company computes a standardized measure of future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.
The "standardized measure" is the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service, depreciation, depletion, and amortization, and tax, and are discounted using an annual discount rate of 10% to reflect timing of future cash flows.
The assumptions used to calculate estimated future cash inflows do not necessarily reflect the Company's expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company's control, such as unexpected delays in development, changes in prices, or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
Prices. All prices used in calculation of our reserves are based upon a twelve month unweighted arithmetic average of the first day of the month price for the twelve months of the fiscal year, unless prices were defined by contractual arrangements. Prices are adjusted for local differentials and gravity and, as required by the SEC, held constant for the life of the projects (i.e., no escalation). The resulting prices used for proved reserves for the fiscal year ended June 30, 2013 are:
 
United States
 
Australia
Oil (per Bbl)
$82.90
 
NA
Gas (per Mcf)
NA
 
$4.92

Costs. Future development and production costs are calculated by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
Income taxes. Future income tax expenses are calculated by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company's proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.
Discount. The present value of future net cash flows from the Company's proved reserves is calculated using a 10% annual discount rate. This rate is not necessarily the same as that used to calculate the current market value of our estimated oil and natural gas reserves.
The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves:
 
United States
 
Australia
 
Total
 
(In thousands)
Fiscal year ended June 30, 2013
 
 
 
 
 
Future cash inflows
$
610,853

 
$
55,947

 
$
666,800

Future production costs
(244,703
)
 
(38,576
)
 
(283,279
)
Future development costs
(28,922
)
 
(4,095
)
 
(33,017
)
Future income tax expense
(112,193
)
 
—

 
(112,193
)
Future net cash flows
225,035

 
13,276

 
238,311

10% annual discount
(127,644
)
 
(2,991
)
 
(130,635
)
Standardized measures of discounted future net cash flows
$
97,391

 
$
10,285

 
$
107,676


 
United States
 
Australia
 
Total
 
(In thousands)
Fiscal year ended June 30, 2012
 
 
 
 
 
Future cash inflows
$
756,405

 
$
53,296

 
$
809,701

Future production costs
(291,212
)
 
(34,729
)
 
(325,941
)
Future development costs
(34,416
)
 
(4,107
)
 
(38,523
)
Future income tax expense
(152,314
)
 
(3,667
)
 
(155,981
)
Future net cash flows
278,463

 
10,793

 
289,256

10% annual discount
(156,967
)
 
(2,214
)
 
(159,181
)
Standardized measures of discounted future net cash flows
$
121,496

 
$
8,579

 
$
130,075


A summary of changes in the standardized measure of discounted future net cash flows is as follows:
 
United States
 
Australia
 
Total
 
(In thousands)
Fiscal year beginning balance
$
110,016

 
$
264

 
$
110,280

Net change in prices and production costs
18,517

 
—

 
18,517

Extensions and discoveries
6,785

 
—

 
6,785

Acquisitions of reserves
26,584

 
4,872

 
31,456

Revisions of previous quantity estimates
(37,846
)
 
6,144

 
(31,702
)
Changes in estimated future development costs
(2,275
)
 
(555
)
 
(2,830
)
Sales and transfers of oil and gas produced
(941
)
 
(264
)
 
(1,205
)
Previously estimated development cost incurred during the period
5,841

 
—

 
5,841

Accretion of discount (1)
—

 
—

 
—

Net change in income taxes
(1,657
)
 
(1,576
)
 
(3,233
)
Net change in timing and other
(3,528
)
 
(306
)
 
(3,834
)
Fiscal year ended June 30, 2012
121,496

 
8,579

 
130,075

Net change in prices and production costs
(7,955
)
 
(624
)
 
(8,579
)
Revisions of previous quantity estimates
(26,503
)
 
192

 
(26,311
)
Changes in estimated future development costs
3,473

 
5

 
3,478

Sales and transfers of oil and gas produced
(20,178
)
 
556

 
(19,622
)
Previously estimated development cost incurred during the period
3,419

 
7

 
3,426

Accretion of discount
19,269

 
1,016

 
20,285

Net change in income taxes
22,258

 
1,577

 
23,835

Net change in timing and other (2)
(17,888
)
 
(1,023
)
 
(18,911
)
Fiscal year ended June 30, 2013
$
97,391

 
$
10,285

 
$
107,676

(1) For fiscal year 2012, the Company assumed no accretion in value of proved oil reserves in the US and Australia. Accretion, with respect to measuring the changes in the standardized measure of reserves values, represents the value benefit of being closer in time, relative to the prior fiscal year's standardized measure, to future cash flows in the reserve projections. During fiscal year 2012, in the US, the Company did not develop its US proved oil reserves in accordance with the reserve plans in place at the beginning of the year, but instead postponed such plans by one year. Therefore, the benefit of accretion of the prior fiscal year's reserves should not have factored into the value of the standardized measure for fiscal year 2012. During fiscal year 2012, in Australia, the reserves at the beginning of the year had been sold entirely during the fiscal year as the long term gas sales contract in place at Palm Valley expired by its term in January 2012. As such, accretion of prior year reserves was not relevant in this case.
(2) For fiscal year 2013, in the US, there was a $17,888 downward revision in reserves value due to changes in timing and other. This revision primarily relates to the change, relative to the prior year reserves projections, in the expected timing of drilling and completing PUD wells and the attendant cash flow expected from these wells. During fiscal year 2013, the Company focused its activities at Poplar on executing water shutoff treatments due to their potential attractive economics. As a result, PUDs previously estimated to be drilled during fiscal year 2013 were postponed, resulting in a change in the annual quantity and timing of PUD wells to be drilled in the current reserves projections.