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WHZ > SEC Filings for WHZ > Form 10-K on 13-Mar-2014All Recent SEC Filings

Show all filings for WHITING USA TRUST II

Form 10-K for WHITING USA TRUST II


13-Mar-2014

Annual Report


Item 7. Trustee's Discussion and Analysis of Financial Condition and Results of Operation

This document contains forward-looking statements, which give our current expectations or forecasts of future events. Please refer to "Forward-Looking Statements" which follows the Table of Contents of this Form 10-K for an explanation of these types of 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 Trust's 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.

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The Trust does not conduct any operations or activities. The Trust's 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 December 31, 2013. The 2013 NPI distributions are mainly affected, however, by October 2012 through September 2013 oil prices and September 2012 through August 2013 natural gas prices.

                                                       2011                                             2012                                             2013
                                     Q1           Q2          Q3          Q4           Q1          Q2          Q3          Q4          Q1          Q2           Q3          Q4
Crude oil (per Bbl)                $ 94.25     $ 102.55     $ 89.81     $ 94.02     $ 102.94     $ 93.51     $ 92.19     $ 88.20     $ 94.34     $ 94.23     $ 105.82     $ 97.50
Natural gas (per MMBtu).           $  4.10     $   4.32     $  4.20     $  3.54     $   2.72     $  2.21     $  2.81     $  3.41     $  3.34     $  4.10     $   3.58     $  3.60

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 (10.61 MMBOE at the 90% 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 December 31, 2013, on a cumulative accrual basis, 3.18 MMBOE (30%) of the Trust's total 10.61 MMBOE have been produced and sold (of which proceeds from the sale of 384 MBOE, which is 90% of 427 MBOE, were distributed to the unitholders in the Trust's February 2014 distribution). The remaining reserve quantities are projected to be produced prior to December 31, 2021, based on the Trust's reserve report as of December 31, 2013. 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 Trust's minimum
10.61 MMBOE have been produced and sold and the expected December 31, 2021 termination date of the Trust occurs, although there is no assurance that this will occur. For additional discussion relating to and of the assumptions underlying the estimated date when 11.79 MMBOE (10.61 MMBOE at the 90% NPI) will be produced and sold from the underlying properties, after which the Trust will soon thereafter wind up its affairs and terminate, see "Description of the Underlying Properties" in Item 2 of this Annual Report on Form 10-K.

For a discussion of material changes to proved reserves, see "Reserves" in Item 2 of this Annual Report on Form 10-K. Additionally, for a discussion of the need to use enhanced recovery techniques, see "Oil and Natural Gas Production" in Item 2 of this Annual Report on Form 10-K.

Capital Expenditure Activities

The primary goal of the planned capital expenditures relative to the underlying properties is to mitigate a portion of the natural decline in production from producing properties. The underlying properties have a capital expenditure budget per the reserve report of $31.5 million estimated to be spent over eight years. No assurance

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can be given, however, that any such expenditures will result in production in 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 operator's historical drilling success rate. With respect to the underlying properties, Whiting expects, but is not obligated, to implement the development strategies described below relative to each of the following regions. 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 "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." Information relating to planned capital expenditures and development activities relating to fields for which Whiting is not the operator represent Whiting's most recent understanding of the planned expenditures and activities of the operator thereof.

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.

                                           2014 - 2021 Planned
                                           Capital Expenditures       Gross       Net
  Region/Field/Description                    (in millions)           Wells      Wells
  Rocky Mountains
  Rangely - CO2 and maintenance capital   $                 18.6          -          -
  Rangely - drill wells                                      0.6           5        0.2
  Garland - maintenance capital                             11.3          -          -

  Rocky Mountains Total                   $                 30.5           5        0.2


  Permian Basin
  Keystone South - recompletions          $                  1.0           1        1.0

  Permian Basin Total                     $                  1.0           1        1.0


  Total                                   $                 31.5           6        1.2

Rocky Mountains Region. The Rangely field, operated by Chevron Corporation, is located in Rio Blanco County, Colorado. This field was discovered in 1931 with development drilling commencing in 1943. The field is currently producing under the tertiary recovery process of CO2 injection. The underlying properties include a 4.6% working interest in the Rangely Weber Sand Unit. Capital is expended each year to purchase CO2 for injection in the field, and capital is also expended for the drilling of additional wells to optimize field recovery. According to information provided by the operator, the 2014 estimated capital expenditures are $2.9 million allocated to the underlying properties' interest and are comprised of development drilling activities, plant and equipment expenditures and CO2 purchases. These capital expenditures scheduled for 2014 include the drilling of four development wells and one injector well. After 2014, Whiting estimates that this level of drilling and facility expenditures as well as CO2 purchases will continue through 2021 and will total approximately $16.3 million as allocated to the underlying properties' interest. Although Whiting is not aware of any other development plans by Chevron or other operators of the underlying properties in this region, these operators may propose capital expenditures in the future. Additionally, although Whiting has not identified any future capital expenditures for the Whiting operated fields in the Rocky Mountains region at this time, further study or offsetting drilling activity may result in capital expenditures in the future.

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Whiting owns a non-operated working interest in the Garland field located in Big Horn County, Wyoming, which produces from the Madison and Tensleep zones. According to information provided by the operator, the estimated capital expenditures allocated to the underlying properties' interest are $1.4 million per year through 2021 related to plant and equipment expenditures. Although Whiting is not aware of any other development plans by this operator or other operators of the underlying properties in this region, these operators may propose capital expenditures in the future.

Permian Basin Region. Whiting operates the Keystone South field in Winkler County, Texas, which produces from several different zones including the Clear Fork, Wichita Albany and Ellenberger zones at depths from 6,500 to 9,200 feet. Whiting plans to recomplete one well from the currently completed zone to another zone expected to be productive in the wellbore. This recompletion is scheduled to be performed in 2014 when the currently producing zones reach their economic limit. The capital expenditures necessary to perform this recompletion are estimated at approximately $1.0 million allocated to the underlying properties' interest. Although Whiting has not identified future capital expenditures for any other operated fields in the Permian Basin at this time, further study or offsetting development activity may result in additional capital expenditures in the future. Additionally, although Whiting is not aware of any other development plans by other operators of the underlying properties in the Permian Basin, these operators may propose capital expenditures in the future.

Although Whiting has not identified any future capital expenditures for its operated fields in the Gulf Coast and Mid-Continent regions at this time, further study or offsetting development activity may result in additional capital expenditures in the future. Additionally, although Whiting is not aware of any development plans by other operators of the underlying properties in these regions, operators may propose capital expenditures in the future.

Results of Trust Operations

Results of the Trust for the Year Ended December 31, 2013 Compared to the Pro Forma Results of the Trust for the Year Ended December 31, 2012

Presented below is a summary of the Trust's income from net profits interest and distributable income for the year ended December 31, 2013, consisting of the February 2013 distribution, May 2013 distribution, August 2013 distribution and November 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 profit interest and distributable income for the Trust for the year ended December 31, 2012 has been presented, so that investors can review comparative results of operations for the Trust for the 2013 and 2012 periods. The Trust's pro forma results of operations for the year ended December 31, 2012 have been presented on a modified cash basis of accounting in the table below. This basis of presentation is consistent with the Trust's financial statements, which have also been prepared on a modified cash basis as described in Note 2 to the Trust's Financial Statements included in this Annual Report on Form 10-K.

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 9 to the Trust's financial statements included in this Annual Report on Form 10-K. 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

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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.

                                     Trust Results
                                                                            Pro Forma
                                                    Year Ended             Year  Ended
                                                   December 31,           December  31,
                                                       2013                  2012(e)
Sales volumes:
Oil from underlying properties (Bbl)(a)                1,299,274 (c)           1,353,169 (f)
Natural gas from underlying properties (Mcf)           2,374,890 (c)           2,683,616 (f)

Total production (BOE)                                 1,695,089               1,800,438
Average sales prices:
Oil (per Bbl)(a)                                   $       84.94          $        86.32
Natural gas (per Mcf)                              $        4.73 (d)      $         5.03 (d)
Costs (per BOE):
Lease operating expenses                           $       25.98          $        23.29
Production taxes                                   $        3.69          $         3.93
Revenues:
Oil sales(a)                                       $ 110,357,643 (c)      $  116,808,893 (f)
Natural gas sales                                     11,235,608 (c)          13,493,055 (f)

Total revenues                                     $ 121,593,251          $  130,301,948

Costs:
Lease operating expenses                           $  44,036,270          $   41,929,928
Production taxes                                       6,254,301               7,082,755
Development Costs                                     10,763,371               6,877,032
Cash settlement (gains) losses on commodity
derivatives(b)                                                -                       -

Total costs                                        $  61,053,942          $   55,889,715

Net proceeds                                       $  60,539,309          $   74,412,233
Net profits percentage                                        90 %                    90 %

Income from net profits interest                   $  54,485,378          $   66,971,010

Provision for estimated Trust expenses                   900,000               1,068,750 (g)
Montana state income tax withheld                         35,222                  59,585 (h)

Distributable income                               $  53,550,156          $   65,842,675

(a) Oil includes natural gas liquids.

(b) As discussed in "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Annual Report on Form 10-K, 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 year ended December 31, 2013 (consisting of Whiting's February 2013 distribution, May 2013 distribution, August 2013 distribution and November 2013 distribution to the Trust) generally represent crude oil production from October 2012 through September 2013 and natural gas production from September 2012 through August 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) 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.

(f) Pro forma oil and gas sales volumes and related revenues for the year ended December 31, 2012 (consisting of Whiting's pro forma February 2012 distribution, May 2012 distribution, August 2012 distribution and November 2012 distribution to the Trust) generally

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represent crude oil production from October 2011 through September 2012 and natural gas production from September 2011 through August 2012.

(g) For the year ended December 31, 2012, actual expenses from the May 2012 distribution, August 2012 distribution and November 2012 distribution were $975,000 and the pro forma provision for estimated Trust expenses for the pro forma February 2012 distribution were assumed to be $93,750.

(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.

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. The 2013 actual oil and natural gas revenues were $8.7 million (or 7%) lower as compared to 2012 pro forma oil and gas revenues. 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 2% and for natural gas by 6% between periods. Additionally, oil volumes declined by 53,895 Bbl (or 4%) and gas volumes declined by 308,726 Mcf (or 12%) when comparing 2013 actual production to 2012 pro forma production volumes. Based on the December 31, 2013 reserve report, overall production attributable to the underlying properties is expected to decline at an average year-over-year rate of approximately 8.4% from 2014 through the estimated December 31, 2021 NPI 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 and fourth quarters of 2013. These oil volume decreases were partially offset, however, by three workover wells that came online during the last twelve months and by differences in timing associated with revenues distributed and received from non-operated parties. Gas sales volume decreases were primarily related to i) normal field production decline, and ii) two gas wells that were shut-in for a portion of the year ended December 31, 2013. One of these shut-in wells resumed consistent production again during the third and fourth quarters of 2013. These gas volume decreases were partially offset by differences in timing associated with revenues distributed and received from non-operated properties.

Lease Operating Expenses. Lease operating expenses ("LOE") in 2013 increased $2.1 million (or 5%) as compared to the 2012 pro forma period primarily due to a $1.9 million increase in ad valorem taxes paid during 2013 as compared to pro forma 2012. This increase in LOE coupled with the decrease in overall production volumes between periods resulted in higher LOE of 12% on a per BOE basis, from $23.29 during the pro forma year ended December 31, 2012 to $25.98 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 year ended December 31, 2013 and pro forma 2012 at 5.1% and 5.4%, respectively. Overall production taxes in 2013, however, decreased $0.8 million (or 12%) as compared to the 2012 pro forma amounts, primarily due to lower oil and natural gas sales revenue between periods.

Development Costs. Actual development costs in 2013 were $3.9 million (or 57%) higher as compared to 2012 pro forma development costs. This increase was primarily due to $1.4 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 Keystone South field of $2.0 million related to four well recompletions.

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Provision for Estimated Trust Expenses. The provision for estimated Trust expenses in 2013 decreased $0.2 million (or 16%) as compared to the 2012 pro forma period primarily due to i) initial start-up legal fees and other administrative costs chargeable to the Trust during the pro forma 2012 period, and ii) a decrease in cash reserves withheld for future Trust expenses of $0.1 million in 2013.

Distributable Income. For the year ended December 31, 2013, the Trust's actual distributable income was $53.6 million and was based on income from net profits interest of $54.5 million, which was reduced by a provision for estimated Trust expenses of $900,000 and Montana state income tax withholdings of $35,222. This compares to pro forma distributable income for 2012 of $65.8 million that was based on pro forma income from net profits interest of $67.0 million, which has been reduced by $1,068,750 for estimated Trust expenses and $59,585 in Montana state income tax withholdings.

Results of the Trust for the Year Ended December 31, 2012 Compared to the Pro Forma Results of the Trust for the Year Ended December 31, 2011

Presented below is a summary of the Trust's income from net profits interest and distributable income for the year ended December 31, 2012, consisting of the May 2012 distribution, August 2012 distribution and November 2012 distribution received by the Trust. In addition, because the Trust had not engaged in any activities during 2011 other than organizational activities, pro forma income from net profit interest and distributable income for the Trust for the year ended December 31, 2011 has been presented, so that investors can review comparative results of operations for the Trust for the 2012 and 2011 periods. The Trust's pro forma results of operations for the year ended December 31, 2011 have been presented on a modified cash basis of accounting in the table below, and this basis of presentation is consistent with the Trust's financial statements, which have also been prepared on a modified cash basis as described in Note 2 to the Trust's Financial Statements included in this Annual Report on Form 10-K.

The pro forma income from net profits interest, distributable income, and related financial data presented below give effect to the Trust formation and the conveyance of the NPI in the underlying properties to the Trust by Whiting, as if they occurred on January 1, 2011. Accordingly, the 2011 pro forma results include four complete quarterly NPI distributions from Whiting to the Trust (the pro forma February, May, August and November 2011 distributions), whereas the 2012 actual results only include three quarterly distributions (consisting of the Trust's actual May 2012 distribution, August 2012 distribution and November 2012 distribution). The pro forma financial information below has been derived from the unaudited pro forma financial statements, as included in the prospectus dated March 22, 2012 for the initial public offering of the Trust's units. 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 . . .

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