Item 2.
Trustees Discussion and Analysis of Financial Condition and
Results of Operations
References to the Trust in this document refer to Whiting USA Trust II. References to
Whiting in this document refer to Whiting Petroleum Corporation and its subsidiaries. References to Whiting Oil and Gas in this document refer to Whiting Oil and Gas Corporation, a 100%-owned subsidiary of Whiting Petroleum
Corporation.
The following review of the Trusts financial condition and results of operations should be read in conjunction with
the financial statements and notes thereto, as well as the Trustees discussion and analysis contained in the Trusts 2012 Annual Report on Form 10-K. The Trusts Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current
Reports on Form 8-K and all amendments to those reports are available on the SECs website
www.sec.gov
.
Note Regarding Forward-Looking
Statements
This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A
of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Quarterly Report on Form 10-Q, including without limitation
the statements under Trustees Discussion and Analysis of Financial Condition and Results of Operations are forward-looking statements. No assurance can be given that such expectations will prove to have been correct. When used in
this document, the words believes, expects, anticipates, intends or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those
discussed elsewhere in this Quarterly Report on Form 10-Q, could affect the future results of the energy industry in general, and Whiting and the Trust in particular, and could cause actual results to differ materially from those expressed in such
forward-looking statements:
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the effect of changes in commodity prices and conditions in the capital markets;
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uncertainty of estimates of oil and natural gas reserves and production;
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risks incident to the operation and drilling of oil and natural gas wells;
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future production and development costs;
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the inability to access oil and natural gas markets due to market conditions or operational impediments;
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failure of the underlying properties to yield oil or natural gas in commercially viable quantities;
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the effect of existing and future laws and regulatory actions;
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competition in the energy industry;
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risks arising out of the hedge contracts;
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inflation or deflation; and
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other risks described under the caption Risk Factors in the Trusts 2012 Annual Report on Form 10-K.
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All subsequent written and oral forward-looking statements attributable to Whiting or the Trust or persons acting on behalf of Whiting or the
Trust are expressly qualified in their entirety by these factors. The Trustee assumes no obligation, and disclaims any duty, to update these forward-looking statements.
Overview and Trust Termination
The
Trust was formed on December 5, 2011. The conveyance of the NPI, however, did not occur until March 28, 2012. As a result, the Trust did not recognize any income or make any distributions during 2011 or during the first quarter of 2012.
The NPI was conveyed effective for production from the underlying properties starting from January 1, 2012. Therefore, the Trusts first quarterly distribution paid on May 30, 2012 consisted of an amount in cash paid by Whiting for
net proceeds generated from the underlying properties since the January 1, 2012 effective date through March 31, 2012.
11
The Trust does not conduct any operations or activities. The Trusts purpose is, in general,
to hold the NPI, to distribute to unitholders cash that the Trust receives in respect of the NPI, and to perform certain administrative functions in respect of the NPI and the Trust units. The Trust derives substantially all of its income and cash
flows from the NPI, which is in turn subject to commodity hedge contracts through December 31, 2014. The NPI entitles the Trust to receive 90% of the net proceeds from the sale of production from the underlying properties.
Oil and gas prices historically have been volatile and may fluctuate widely in the future. The table below highlights these price trends by
listing quarterly average NYMEX crude oil and natural gas prices for the periods indicated through September 30, 2013. The August 2013 distribution in the third quarter of 2013 was mainly affected, however, by April 2013 through June 2013 oil
prices and March 2013 through May 2013 natural gas prices.
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2011
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2012
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2013
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Q1
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Q2
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Q3
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Q4
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Q1
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Q2
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Q3
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Q4
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Q1
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Q2
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Q3
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Crude Oil (per Bbl)
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$
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94.25
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$
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102.55
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$
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89.81
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$
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94.02
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$
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102.94
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$
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93.51
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$
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92.19
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$
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88.20
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$
|
94.34
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$
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94.23
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$
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105.82
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Natural Gas (per MMBtu)
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$
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4.10
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$
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4.32
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$
|
4.20
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$
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3.54
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$
|
2.72
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$
|
2.21
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$
|
2.81
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$
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3.41
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$
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3.34
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$
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4.10
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$
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3.58
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Lower oil and gas prices on production from the underlying properties could cause the following: (i) a
reduction in the amount of net proceeds to which the Trust is entitled; and (ii) a reduction in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties causing an extension of the length
of time required to produce 11.79 MMBOE (10.61 MMBOE at the 90% NPI). Alternatively, higher oil and natural gas prices may potentially result in the following: (i) an increase in the amount of oil, natural gas and natural gas liquids that is
economic to produce from the underlying properties, and (ii) cash settlement losses on commodity derivatives.
Trust Termination.
The NPI will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the
Trusts right to receive 90% of the net proceeds from such reserves pursuant to the NPI), and the Trust will soon thereafter wind up its affairs and terminate, after which it will pay no further distributions. Since the assets of the Trust are
depleting assets, a portion of each cash distribution paid on the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment or yield. As a result, the market price of the
Trust units will decline to zero at termination of the Trust. As of September 30, 2013 on a cumulative accrual basis, 2.8 MMBOE (26%) of the Trusts total 10.61 MMBOE have been produced and sold (of which proceeds from the sale of 382
MBOE, which is 90% of 425 MBOE, will be distributed to the unitholders in the Trusts forthcoming November 2013 distribution). The remaining reserve quantities are projected to be produced prior to December 31, 2021, based on the
Trusts reserve report as of December 31, 2012. Since the Trust is not currently expected to contractually terminate until December 31, 2021, additional reserves and production attributable to the NPI may be available for distribution
to unitholders (also based on the year-end reserve report) between the time that the Trusts minimum 10.61 MMBOE have been produced and sold and the expected December 31, 2021 termination date of the Trust occurs.
Capital Expenditure Activities
The
primary goals of the planned capital expenditures relative to the underlying properties are to convert proved undeveloped reserves and developed non-producing properties to producing properties and to make the capital expenditures with a goal of
mitigating a portion of the natural decline in production from producing properties. The underlying properties have a capital expenditure budget per the December 31, 2012 reserve report of $26.3 million estimated to be spent over 9 years. No
assurance can be given, however, that any such expenditures will result in the production of commercially paying amounts, if any, or that the characteristics of any newly developed well will match the characteristics of existing wells on the
underlying properties or the operators historical drilling success rate. With respect to fields for which Whiting is not the operator, Whiting will have limited control over the timing and amount of capital expenditures relative to such
fields. Please read the Trusts Annual Report on Form 10-K for the fiscal year ended December 31, 2012, Item 1A. Risk Factors Whiting has limited control over activities on the underlying properties that Whiting does not
operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to Trust unitholders.
12
During each twelve-month period beginning on the later to occur of (1) December 31,
2017 and (2) the time when 8.24 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 7.41 MMBOE attributable to the 90% NPI) (in either case, the capital expenditure limitation date), the sum
of the capital expenditures and amounts reserved for approved capital expenditure projects for such twelve-month period may not exceed the average annual capital expenditure amount. The average annual capital expenditure amount means the
quotient of (x) the sum of the capital expenditures and amounts reserved for approved capital expenditure projects with respect to the three twelve-month periods ending on the capital expenditure limitation date, divided by (y) three.
Commencing on the capital expenditure limitation date, and each anniversary of the capital expenditure limitation date thereafter, the average annual capital expenditure amount will be increased by 2.5% to account for expected increased costs due to
inflation.
The following table presents the underlying properties aggregate capital expenditures attributable to the February 2013
distribution, the May 2013 distribution and the August 2013 distribution (in thousands):
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Region
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2013 Capital
Expenditures
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Rocky Mountains
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$
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4,254
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Permian Basin
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3,663
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Gulf Coast
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53
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Mid-Continent
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6
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Total
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$
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7,976
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Results of Trust Operations
Results of the Trust for the Nine Months Ended September 30, 2013 Compared to the Pro Forma Results of the Trust for the Nine Months
Ended September 30, 2012
Presented below is a summary of the Trusts income from net profits interest and distributable
income for the nine months ended September 30, 2013, consisting of the February 2013 distribution, the May 2013 distribution and the August 2013 distribution received by the Trust. In addition, because the Trust had not engaged in any
activities during the three months ended March 31, 2012 other than organizational activities, pro forma income from net profits interest and distributable income for the Trust for the nine months ended September 30, 2012 has been
presented, so that investors can review comparative results of operations for the Trust for the 2013 and 2012 periods. The Trusts pro forma results of operations for the nine months ended September 30, 2012 have been presented on a
modified cash basis of accounting in the table below. This basis of presentation is consistent with the Trusts financial statements, which have also been prepared on a modified cash basis as described in Note 1 to the Trusts financial
statements included in this Quarterly Report on Form 10-Q.
The pro forma income from net profits interest, distributable income, and
related financial data presented below assume (i) that the conveyance of the NPI in the underlying properties occurred on December 5, 2011, and (ii) that the NPI was effective for oil and gas production from the underlying properties
beginning in 2011. The pro forma financial information below has been derived from the unaudited pro forma financial statement, as included in Note 8 to the Trusts financial statements included in this Quarterly Report on Form 10-Q. The Trust
believes that the assumptions used to prepare this pro forma data provide a reasonable basis for presenting the effects directly attributable to these transactions. However, the pro forma amounts set forth in the table below are for informational
purposes only and do not purport to present the results that would have actually occurred had the Trust formation and net profits interest conveyance been completed on December 5, 2011 as indicated above, nor are they indicative of future
results of operations.
13
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Trust Results (Dollars in thousands, except
per Bbl, per Mcf and per BOE amounts)
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Nine Months Ended
September 30, 2013
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Pro Forma Nine
Months Ended
September 30, 2012
(e)
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Sales volumes:
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Oil from underlying properties (Bbl)
(a)
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971,634
(c)
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1,006,245
(f)
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Natural gas from underlying properties (Mcf)
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1,791,713
(c)
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1,999,248
(f)
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Total production (BOE)
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1,270,253
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1,339,453
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Average sales prices:
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Oil (per Bbl)
(a)
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$
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81.36
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$
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88.17
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Natural gas (per Mcf)
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$
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4.72
(d)
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$
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5.34
(d)
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Costs (per BOE):
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Lease operating expenses
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$
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25.90
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|
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$
|
22.41
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|
Production taxes
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|
$
|
3.53
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|
|
$
|
4.03
|
|
Revenues:
|
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Oil sales
(a)
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$
|
79,049
(c)
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$
|
88,719
(f)
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|
Natural gas sales
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8,454
(c)
|
|
|
|
10,669
(f)
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|
|
|
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|
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Total revenues
|
|
|
87,503
|
|
|
|
99,388
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|
|
|
|
|
|
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|
Costs:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
32,897
|
|
|
|
30,022
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|
Production taxes
|
|
|
4,484
|
|
|
|
5,400
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|
Development costs
|
|
|
7,976
|
|
|
|
5,499
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|
Realized (gains) losses on hedging settlements
(b)
|
|
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-
|
|
|
|
-
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|
|
|
|
|
|
|
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Total costs
|
|
|
45,357
|
|
|
|
40,921
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|
|
|
|
|
|
|
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|
|
Net proceeds
|
|
|
42,146
|
|
|
|
58,467
|
|
Net profits percentage
|
|
|
90%
|
|
|
|
90%
|
|
|
|
|
|
|
|
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Income from net profits interest
|
|
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37,931
|
|
|
|
52,620
|
|
|
|
|
|
|
|
|
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Provision for estimated Trust expenses
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|
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(700)
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|
|
|
(719)
(g)
|
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Montana state income tax withheld
|
|
|
(25)
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|
|
|
(54)
(h)
|
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|
|
|
|
|
|
|
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Distributable income
|
|
$
|
37,206
|
|
|
$
|
51,847
|
|
|
|
|
|
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(a)
|
Oil includes natural gas liquids.
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(b)
|
As discussed in Item 3. Quantitative and Qualitative Disclosures About Market Risk in this Quarterly Report on Form 10-Q, all costless collar
hedge contracts terminate as of December 31, 2014. Consequently, for all distributions after the February 2015 distribution, there will be no further cash settlement gains or losses on commodity hedges, and the Trust will have increased
exposure to oil and natural gas price volatility.
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(c)
|
Oil and gas sales volumes and related revenues for the nine months ended September 30, 2013 (consisting of Whitings February 2013
distribution, May 2013 distribution and August 2013 distribution to the Trust) generally represent crude oil production from October 2012 through June 2013 and natural gas production from September 2012 through May 2013.
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(d)
|
The average sales price of natural gas for the gas production months within the distribution period exceeded the average NYMEX gas prices for those
same months within the period due to the liquids rich content of a portion of the natural gas volumes produced by the underlying properties.
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(e)
|
Pro forma sales volumes, average sales prices, costs and revenue data have been derived from the historical accounting records of the underlying
properties. Such amounts were prepared by adjusting the accrual basis information from the historical revenue and direct operating expenses of the underlying properties to a modified cash basis of accounting.
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(f)
|
Pro forma oil and gas sales volumes and related revenues for the nine months ended September 30, 2012 (consisting of Whitings pro forma
February 2012 distribution, May 2012 distribution and August 2012 distribution to the Trust) generally represent crude oil production from October 2011 through June 2012 and natural gas production from September 2011 through May 2012.
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(g)
|
For the nine months ended September 30, 2012, actual expenses from the May 2012 distribution and August 2012 distribution were $625,000 and
the pro forma provision for estimated Trust expenses for the pro forma February 2012 distribution were assumed to be $50,000 and $43,750, respectively.
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14
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(h)
|
Pro forma Montana state income tax withheld assumes that for Montana state income tax purposes, Whiting must withhold from its NPI payments to the
Trust, an amount equal to 6% of the net amount payable to the Trust from the sale of oil and gas in Montana.
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Income
from Net Profits Interest.
Income from net profits interest is recorded on a cash basis when NPI proceeds are received by the Trust from Whiting. NPI proceeds that Whiting remits to the Trust are based on the oil and gas production Whiting has
received payment for within one month following the end of the most recent fiscal quarter. Whiting receives payment for its crude oil sales generally within 30 days following the month in which it is produced, and Whiting receives payment for its
natural gas sales generally within 60 days following the month in which it is produced. Income from net profits interest is generally a function of oil and gas revenues, lease operating expenses, production taxes and development costs as follows:
Revenues.
Oil and natural gas revenues were $11.9 million (or 12%) lower for the nine months ended
September 30, 2013 as compared to the same pro forma 2012 period. Sales revenue is a function of average commodity prices realized and oil and gas volumes sold. The decrease in revenue between periods was due to lower sales prices realized for
oil and natural gas and lower oil and natural gas production volumes during 2013 as compared to the 2012 pro forma period. The average sales price realized declined for crude oil by 8% and for natural gas by 12% between periods. Additionally, oil
volumes declined by 34,611 Bbl (or 3%) and gas volumes declined by 207,535 Mcf (or 10%) when comparing 2013 actual production to 2012 pro forma production volumes. Based on the December 31, 2012 reserve report, overall production attributable
to the underlying properties is expected to decline at an average year-over-year rate of approximately 9% from 2013 through the estimated December 31, 2021 Trust termination date. Oil sales volumes decreased period over period primarily due to
normal field production decline and a shut-in well, which was off-line during the first quarter of 2013 and during portions of the second quarter of 2013. This well returned to normal production during the third quarter of 2013. These oil volume
decreases were partially offset, however, by one newly drilled oil well and three additional workover wells that came online during the last twelve months. Gas sales volume decreases were primarily related to i) normal field production decline, and
ii) differences in timing associated with revenues distributed and received from non-operated properties. Additionally, there were two gas wells that were shut-in for a portion of the nine month period ended September 30, 2013, but one of these
shut-in wells had consistent production again from July 2013 going forward.
Lease Operating Expenses.
Lease
operating expenses (LOE) increased $2.9 million (or 10%) during the first nine months of 2013 compared to the same pro forma 2012 period primarily due to a $1.8 million increase in ad valorem taxes and a $0.7 million increase in the cost
of oilfield goods and services (which includes workover activity) caused by increased demand in the oil and gas industry. These increases in LOE coupled with the decrease in overall production volumes between periods resulted in higher LOE of 16% on
a per BOE basis, from $22.41 during the pro forma first nine months of 2012 to $25.90 for the same period in 2013.
Production Taxes.
Production taxes are typically calculated as a percentage of oil and gas revenues, and production
taxes as a percent of revenues remained relatively consistent for the first nine months of 2013 and pro forma 2012 at 5.1% and 5.4%, respectively. Overall production taxes for the first nine months of 2013, however, decreased $0.9 million (or 17%)
as compared to the 2012 pro forma amounts, primarily due to lower oil and natural gas sales revenue between periods.
Development Costs.
Development costs for the nine months ended September 30, 2013 were $2.5 million (or 45%)
higher as compared to 2012 pro forma development costs for the same period. This increase was primarily due to $1.5 million in capital expenditures incurred at the Rangely Weber field in connection with new drilling and facility expansions being
carried out at this project. Also contributing to higher development costs between periods was an increase in capital expenditures at the Sandtank Bone Spring field of $0.9 million related to a new drilling project in this area.
Provision for Estimated Trust Expenses.
The provision for estimated Trust expenses for the first nine months of 2013 remained
relatively consistent with this same provision included in the 2012 pro forma results.
Distributable Income.
For the nine months
ended September 30, 2013, the Trusts actual distributable income was $37.2 million and was based on income from net profits interest of $37.9 million, reduced by a provision for estimated Trust expenses of $700,000 and Montana state
income tax withholdings of $25,143. This compares to pro forma distributable income for the first nine months of 2012 of $51.8 million, which was based on pro forma income from net profits interest of $52.6 million, reduced by $718,750 for pro forma
Trust administrative expenses and $54,072 in pro forma Montana state income tax withholdings.
15
Results of the Trust for the Three Months Ended September 30, 2013 Compared to the
Results of the Trust for the Three Months Ended September 30, 2012
The following is a summary of income from the net profits
interest received by the Trust for the three months ended September 30, 2013 and 2012, consisting of the August 2013 distribution and the August 2012 distribution for each respective year (dollars in thousands, except per Bbl, per Mcf and per
BOE amounts):
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|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2013
|
|
|
2012
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
Oil from underlying properties (Bbl)
(a)
|
|
|
314,344
(c)
|
|
|
|
356,599
(e)
|
|
Natural gas from underlying properties (Mcf)
|
|
|
594,295
(c)
|
|
|
|
655,398
(e)
|
|
|
|
|
|
|
|
|
|
|
Total production (BOE)
|
|
|
413,393
|
|
|
|
465,832
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
(a)
|
|
$
|
85.19
|
|
|
$
|
84.06
|
|
Natural gas (per Mcf)
|
|
$
|
4.89
(d)
|
|
|
$
|
4.48
(d)
|
|
Costs (per BOE):
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
26.39
|
|
|
$
|
24.57
|
|
Production taxes
|
|
$
|
3.65
|
|
|
$
|
3.66
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil sales
(a)
|
|
$
|
26,780
(c)
|
|
|
$
|
29,976
(e)
|
|
Natural gas sales
|
|
|
2,907
(c)
|
|
|
|
2,936
(e)
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
29,687
|
|
|
|
32,912
|
|
|
|
|
|
|
|
|
|
|
Costs:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
10,910
|
|
|
|
11,447
|
|
Production taxes
|
|
|
1,509
|
|
|
|
1,706
|
|
Development costs
|
|
|
1,919
|
|
|
|
1,321
|
|
Realized (gains) losses on hedging settlements
(b)
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Total costs
|
|
|
14,338
|
|
|
|
14,474
|
|
|
|
|
|
|
|
|
|
|
Net proceeds
|
|
|
15,349
|
|
|
|
18,438
|
|
Net profits percentage
|
|
|
90%
|
|
|
|
90%
|
|
|
|
|
|
|
|
|
|
|
Income from net profits interest
|
|
|
13,814
|
|
|
|
16,594
|
|
|
|
|
|
|
|
|
|
|
Provision for estimated Trust expenses
|
|
|
(200)
|
|
|
|
(125)
|
|
Montana state income tax withheld
|
|
|
(10)
|
|
|
|
(13)
|
|
|
|
|
|
|
|
|
|
|
Distributable income
|
|
$
|
13,604
|
|
|
$
|
16,456
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Oil includes natural gas liquids.
|
|
(b)
|
As discussed in Item 3. Quantitative and Qualitative Disclosures About Market Risk in this Quarterly Report on Form 10-Q, all costless collar
hedge contracts terminate as of December 31, 2014. Consequently, for all distributions after the February 2015 distribution, there will be no further cash settlement gains or losses on commodity hedges, and the Trust will have increased
exposure to oil and natural gas price volatility.
|
|
(c)
|
Oil and gas sales volumes and related revenues for the three months ended September 30, 2013 (consisting of Whitings August 2013
distribution to the Trust) generally represent crude oil production from April 2013 through June 2013 and natural gas production from March 2013 through May 2013.
|
|
(d)
|
The average sales price of natural gas for the gas production months within the distribution period exceeded the average NYMEX gas prices for those
same months within the period due to the liquids rich content of a portion of the natural gas volumes produced by the underlying properties.
|
|
(e)
|
Oil and gas sales volumes and related revenues for the three months ended September 30, 2012 (consisting of the August 2012 distribution)
generally represent crude oil production from April 2012 through June 2012 and natural gas production from March 2012 through May 2012.
|
16
Income from Net Profits Interest.
Income from net profits interest is recorded on a cash
basis when NPI proceeds are received by the Trust from Whiting. NPI proceeds that Whiting remits to the Trust are based on the oil and gas production Whiting has received payment for within one month following the end of the most recent fiscal
quarter. Whiting receives payment for its crude oil sales generally within 30 days following the month in which it is produced, and Whiting receives payment for its natural gas sales generally within 60 days following the month in which it is
produced. Income from net profits interest is generally a function of oil and gas revenues, lease operating expenses, production taxes and development costs as follows:
Revenues.
Oil and natural gas revenues were $3.2 million (or 10%) lower for the three months ended September 30,
2013 as compared to the same 2012 period. Sales revenue is a function of average commodity prices realized and oil and gas volumes sold. The average sales price realized increased for crude oil by 1% and for natural gas by 9% between periods. The
decrease in revenue between periods, however, was due to lower oil and natural gas production in the third quarter of 2013 compared to the third quarter of 2012. Oil volumes decreased by 42,255 Bbl (or 12%) and gas production volumes decreased by
61,103 Mcf (or 9%) when comparing the third quarter of 2013 to the same period in 2012. Based on the December 31, 2012 reserve report, overall production attributable to the underlying properties is expected to decline at an average
year-over-year rate of approximately 9% from 2013 through the estimated December 31, 2021 Trust termination date. Crude oil volume decreases during the third quarter of 2013 were primarily related to i) differences in timing associated with
revenues distributed and received from non-operated properties, ii) normal field production decline, and iii) one well that was shut-in for a portion of the 2013 period. These oil volume decreases were partially offset, however, by one workover well
that came online during the last twelve months. As for gas production, gas sales volumes decreased between periods primarily due to i) normal field production decline and ii) differences in timing associated with revenues distributed and received
from non-operated properties. Additionally, there was one well that was temporarily abandoned for the period covered by the August 2013 distribution. This well will most likely not return to production during 2013. These gas volume decreases were
partially offset by one newly drilled gas well in New Mexico and production increases generated by four gas wells in Texas and one well in New Mexico.
Lease Operating Expenses.
Lease operating expenses (LOE) decreased $0.5 million (or 5%) during the third
quarter of 2013 compared to the same 2012 period primarily due to a $0.9 million decrease in workover activity. LOE on a per BOE basis, however, increased 7% from $24.57 during the third quarter of 2012 to $26.39 for the same period in 2013. This
higher LOE rate was mainly due to overall production declining at a faster rate than the fixed and semi-variable costs attributable to the underlying properties.
Production Taxes
. Production taxes are typically calculated as a percentage of oil and gas revenues, and production
taxes as a percent of revenues remained relatively consistent for the three months ended September 30, 2013 and 2012 at 5.1% and 5.2%, respectively. Overall production taxes for the third quarter of 2013, however, decreased $0.2 million (or
12%) as compared to the same period in 2012, primarily due to lower oil sales revenue between periods.
Development
Costs
. Development costs for the three months ended September 30, 2013 were $0.6 million (or 45%) higher as compared to 2012 development costs for the same period. This increase was primarily driven by $0.6 million in capital expenditures
incurred at the Rangely Weber field related to new drilling and facility expansions being carried out at this project.
Provision for
Estimated Trust Expenses.
The provision for estimated Trust expenses in the second quarter of 2013 was $75,000 higher than this same provision included in the 2012 results. This increase was mainly due to the fact that cash reserves used
declined from $114,504 for the third quarter of 2012 to no amount used, but rather cash reserves withheld for future Trust expenses of $18,857, for the same period in 2013. This higher cash reserve was partially offset by decreasing general and
administrative costs.
Distributable Income.
For the three months ended September 30, 2013, the Trusts
actual distributable income was $13.6 million and was based on income from net profits interest of $13.8 million, reduced by a provision for estimated Trust expenses of $200,000 and Montana state income tax withholdings of $9,832. This compares to
distributable income for the three months ended September 30, 2012 of $16.5 million and was based on income from net profits interest of $16.6 million, reduced by a provision for estimated Trust expenses of $125,000 and $13,444 in Montana state
income tax withholdings.
17
Liquidity and Capital Resources
The Trust has no source of liquidity or capital resources other than cash flows from the NPI. Other than Trust administrative expenses,
including any reserves established by the Trustee for future liabilities, the Trusts only use of cash is for distributions to Trust unitholders. Administrative expenses include payments to the Trustee and the Delaware Trustee, a quarterly fee
to Whiting pursuant to an administrative services agreement, and expenses in connection with the discharge of the Trustees duties, including third party engineering, audit, accounting and legal fees. Each quarter, the Trustee determines the
amount of funds available for distribution to unitholders. Available funds are the excess cash, if any, received by the Trust from the NPI and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the
Trusts expenses for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. The Trustee may borrow funds required to pay liabilities if the Trustee determines that the cash on
hand and the cash to be received are insufficient to cover the Trusts liabilities. If the Trustee borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid.
Income to the Trust from the NPI is based on the calculation and definitions of gross proceeds and net proceeds
contained in the conveyance agreement, which is listed as an exhibit to this report, and reference is hereby made to such conveyance agreement for the actual definitions of gross proceeds and net proceeds.
Whiting may reserve from the gross proceeds amounts up to a total of $2.0 million at any time for future development, maintenance or operating
expenses. However, Whiting has not funded such a reserve since the inception of the Trust, including during the nine month periods ended September 30, 2013 and 2012. Instead, Whiting deducted from the gross proceeds only actual costs paid for
development, maintenance and operating expenses.
Plugging and abandonment costs related to the underlying properties, net of any proceeds
received from the salvage of equipment, cannot be included as a deduction in the calculation of net proceeds pursuant to the terms of the conveyance agreement. During the three and nine months ended September 30, 2013, Whiting incurred $0.5
million and $1.2 million, respectively, of plugging and abandonment charges on the underlying properties that were not passed on to the unitholders of the Trust.
In June 2012, Whiting established a letter of credit in the amount of $1.0 million in favor of the Trustee to provide a mechanism for the
Trustee to pay the operating expenses of the Trust, in the event that Whiting should fail to lend funds to the Trust if requested to do so by the Trustee. This letter of credit will not be used to fund NPI distributions to unitholders, and Whiting
has no obligation to lend funds to the Trust. If the Trustee were to draw on the letter of credit or borrow funds from Whiting or otherwise, no further distributions would be made to unitholders until all such amounts have been repaid by the Trust.
The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could
materially affect the Trusts liquidity or the availability of capital resources.
Future Trust Distributions to Unitholders
On November 7, 2013, the Trustee announced the Trust distribution of net profits for the third quarterly payment period in 2013.
Unitholders of record on November 19, 2013 are expected to receive a distribution of $0.888253 per Trust unit, which is payable on or before November 29, 2013. This aggregate distribution to all Trust unitholders is expected to consist of
net cash proceeds of $16.6 million paid by Whiting to the Trust, less a provision of $200,000 for estimated Trust expenses and $10,079 for Montana state income tax withholdings. There were no realized gains or losses on hedge settlements during the
third quarterly payment period of 2013.
New Accounting Pronouncements
There were no accounting pronouncements issued during the nine months ended September 30, 2013 applicable to the Trust or its financial
statements.
18
Critical Accounting Policies and Estimates
A disclosure of critical accounting policies and the more significant judgments and estimates used in the preparation of the Trusts
financial statements is included in Item 7 of the Trusts Annual Report on Form 10-K for the year ended December 31, 2012. There have been no significant changes to the critical accounting policies during the nine months ended
September 30, 2013.