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WHZ > SEC Filings for WHZ > Form 10-Q on 13-Nov-2013All Recent SEC Filings

Show all filings for WHITING USA TRUST II

Form 10-Q for WHITING USA TRUST II


13-Nov-2013

Quarterly Report


Item 2. Trustee's 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 Trust's financial condition and results of operations should be read in conjunction with the financial statements and notes thereto, as well as the Trustee's discussion and analysis contained in the Trust's 2012 Annual Report on Form 10-K. The Trust's 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 SEC's 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 "Trustee's 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:

the effect of changes in commodity prices and conditions in the capital markets;

uncertainty of estimates of oil and natural gas reserves and production;

risks incident to the operation and drilling of oil and natural gas wells;

future production and development costs;

the inability to access oil and natural gas markets due to market conditions or operational impediments;

failure of the underlying properties to yield oil or natural gas in commercially viable quantities;

the effect of existing and future laws and regulatory actions;

competition in the energy industry;

risks arising out of the hedge contracts;

inflation or deflation; and

other risks described under the caption "Risk Factors" in the Trust's 2012 Annual Report on Form 10-K.

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 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 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.

                                              2011                                             2012                                       2013
                            Q1           Q2          Q3          Q4           Q1          Q2          Q3          Q4          Q1          Q2           Q3
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
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

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 Trust's 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 Trust's 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 Trust's forthcoming November 2013 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, 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 Trust's 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 operator's 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 Trust's 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."


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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):

                                           2013 Capital
                    Region                 Expenditures
                    Rocky Mountains    $              4,254
                    Permian Basin                     3,663
                    Gulf Coast                           53
                    Mid-Continent                         6

                    Total              $              7,976

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 Trust's 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 Trust's 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 Trust's financial statements, which have also been prepared on a modified cash basis as described in Note 1 to the Trust's 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 Trust's 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.


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Trust Results (Dollars in thousands, except per Bbl, per Mcf and per BOE amounts)
                                                                                                   Pro Forma Nine
                                                            Nine Months Ended                       Months Ended
                                                            September 30, 2013                 September 30, 2012(e)
Sales volumes:
Oil from underlying properties (Bbl) (a)                              971,634 (c)                        1,006,245 (f)
Natural gas from underlying properties (Mcf)                        1,791,713 (c)                        1,999,248 (f)

Total production (BOE)                                                1,270,253                            1,339,453
Average sales prices:
Oil (per Bbl) (a)                                      $                  81.36             $                  88.17
Natural gas (per Mcf)                                  $                 4.72 (d)           $                 5.34 (d)
Costs (per BOE):
Lease operating expenses                               $                  25.90             $                  22.41
Production taxes                                       $                   3.53             $                   4.03
Revenues:
Oil sales (a)                                          $               79,049 (c)           $               88,719 (f)
Natural gas sales                                                       8,454 (c)                           10,669 (f)

Total revenues                                                           87,503                               99,388

Costs:
Lease operating expenses                                                 32,897                               30,022
Production taxes                                                          4,484                                5,400
Development costs                                                         7,976                                5,499
Realized (gains) losses on hedging settlements (b)                            -                                    -

Total costs                                                              45,357                               40,921

Net proceeds                                                             42,146                               58,467
Net profits percentage                                                        90%                                  90%

Income from net profits interest                                         37,931                               52,620

Provision for estimated Trust expenses                                     (700)                             (719) (g)
Montana state income tax withheld                                           (25)                              (54) (h)

Distributable income                                   $                 37,206             $                 51,847

(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 nine months ended September 30, 2013 (consisting of Whiting's 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.

(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 nine months ended September 30, 2012 (consisting of Whiting's 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.

(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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(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. 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 Trust's 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.


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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):

                                                            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 Whiting's 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 . . .

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