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WHX > SEC Filings for WHX > Form 10-K on 15-Mar-2013All Recent SEC Filings

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Form 10-K for WHITING USA TRUST I


15-Mar-2013

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

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 was in turn subject to commodity hedge contracts through December 2012. 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 following table highlights these price trends by listing quarterly average NYMEX crude oil and natural gas prices for the periods indicated through September 30, 2012. The 2012 NPI distributions are mainly affected, however, by October 2011 through September 2012 oil prices and by September 2011 through August 2012 natural gas prices.

                                                              2010                                             2011                                       2012
                                             Q1          Q2          Q3          Q4          Q1           Q2          Q3          Q4           Q1          Q2          Q3
Crude oil (per Bbl)                        $ 78.79     $ 77.99     $ 76.21     $ 85.18     $ 94.25     $ 102.55     $ 89.81     $ 94.02     $ 102.94     $ 93.51     $ 92.19
Natural gas (per MMBtu)                    $  5.30     $  4.09     $  4.39     $  3.81     $  4.10     $   4.32     $  4.20     $  3.54     $   2.72     $  2.21     $  2.81

Although oil prices fell significantly after reaching highs in the third quarter of 2008, they have experienced a rebound in 2010, 2011 and 2012. Natural gas prices have likewise fallen significantly since their peak in the third quarter of 2008 but have remained low throughout 2009, 2010 and 2011. In addition, natural gas prices declined during the first half of 2012, but have begun to improve in recent months. The following table highlights the settled NYMEX prices for natural gas for January 2012 through March 2013:

                                                                                                         2012                                                                               2013
                                             Jan.       Feb.       Mar.       Apr.       May        June       July       Aug.      Sept.       Oct.       Nov.       Dec.       Jan.       Feb.       Mar.
Natural gas
(per MMBtu)                                 $ 3.08     $ 2.68     $ 2.41     $ 2.19     $ 2.03     $ 2.42     $ 2.77     $ 3.01     $ 2.63     $ 3.06     $ 3.47     $ 3.71     $ 3.35     $ 3.23     $ 3.43


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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; (ii) a reduction in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties; and (iii) an extension of the length of time required to produce 9.11 MMBOE (8.20 MMBOE at the 90% NPI) due to some wells thereby reaching their economic limits sooner. Alternatively, higher oil and natural gas prices may potentially result in an increase in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties. All costless collar hedge contracts Whiting entered into, and in turn conveyed to the Trust, terminated as of December 31, 2012, and no additional hedges are allowed to be placed on the Trust assets. Consequently, for production after December 31, 2012, there will be no cash settlement gains or losses on commodity derivatives, and the Trust will have increased exposure to oil and natural gas price volatility.

Trust termination. The NPI will terminate when 9.11 MMBOE have been produced and sold from the underlying properties (which amount is equivalent to 8.20 MMBOE attributable 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. As a result, the market price of the Trust units will decline to zero at termination of the Trust. As of December 31, 2012 on a cumulative accrual basis, 6.10 MMBOE (74%) of the Trust's total 8.20 MMBOE have been produced and sold (of which proceeds from the sale of 263 MBOE, which is 90% of 292 MBOE, have been distributed to unitholders in the Trust's March 1, 2013 distribution) and a cumulative reserve quantity of 0.02 MMBOE have been divested. For additional discussion relating to, and of the assumptions underlying, the estimated date when 9.11 MMBOE (8.20 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.


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Results of Trust Operations

The following is a summary of income from net profits interest received by the Trust for the years ended December 31, 2012, 2011 and 2010, consisting of the February, May, August and November distributions for each respective year (dollars in thousands, except per Bbl, per Mcf and per BOE amounts):

                                                                  Year Ended December 31,
                                                           2012             2011             2010
Sales volumes:
Oil from underlying properties (MBbl)                       762(a)           760(b)           804(c)
Natural gas from underlying properties (MMcf)             2,805(a)         2,947(b)         3,335(c)

Total production (MBOE)                                    1,229            1,251            1,360

Average sales prices:
Oil (per Bbl)                                          $   80.78           $80.16        $   65.39
Effect of oil hedges on average price (per Bbl) (d)            -                -             0.25

Oil net of hedging (per Bbl)                           $   80.78        $   80.16        $   65.64


Natural gas (per Mcf)                                  $    3.16        $    4.12        $    4.26
Effect of natural gas hedges on average price (per
Mcf) (d)                                                    2.12             1.51             1.23

Natural gas net of hedging (per Mcf)                   $    5.28        $    5.63        $    5.49

Costs (per BOE):
Lease operating expenses                               $   23.99        $   20.44        $   17.39
Production taxes                                       $    3.90        $    4.25        $    3.47
Revenues:
Oil sales                                              $ 61,542(a)      $ 60,886(b)      $ 52,558(c)
Natural gas sales                                         8,877(a)        12,135(b)        14,193(c)

Total revenues                                         $  70,419        $  73,021        $  66,751

Costs:
Lease operating expenses                               $  29,495        $  25,569        $  23,643
Production taxes                                           4,799            5,310            4,718
Cash settlement gains received on commodity
derivatives (d)                                           (5,937)          (4,450)          (4,323)

Total costs                                            $  28,357        $  26,429        $  24,038

Net proceeds                                           $  42,062        $  46,592        $  42,713
Net profits percentage                                         90%              90%              90%

Income from net profits interest                       $  37,856        $  41,933        $  38,442

(a) Oil and gas sales volumes and related revenues for the year ended December 31, 2012 (consisting of Whiting's February, May, August and November 2012 NPI distributions to the Trust) generally represent crude oil production from October 2011 through September 2012 and natural gas production from September 2011 through August 2012.


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(b) Oil and gas sales volumes and related revenues for the year ended December 31, 2011 (consisting of Whiting's February, May, August and November 2011 NPI distributions to the Trust) generally represent crude oil production from October 2010 through September 2011 and natural gas production from September 2010 through August 2011.

(c) Oil and gas sales volumes and related revenues for the year ended December 31, 2010 (consisting of Whiting's February, May, August and November 2010 NPI distributions to the Trust) generally represent crude oil production from October 2009 through September 2010 and natural gas production from September 2009 through August 2010.

(d) As discussed below, all hedges terminated as of December 31, 2012.

Comparison of Results of the Trust for the Years Ended December 31, 2012 and 2011

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 cash settlements on commodity derivatives as follows:

Revenues. Oil and natural gas revenues decreased $2.6 million or 4% in 2012 compared to 2011. Revenues are a function of oil and natural gas sales prices and production volumes sold. The decrease in revenue between periods was due to lower sales prices realized for natural gas in 2012 and lower natural gas production volumes, which effect was partially offset by higher sales prices realized for crude oil during 2012. The average price for gas before the effects of hedging decreased 23% between periods, while the average price for oil before the effects of hedging increased 1%. Gas sales volumes decreased 5% or 142 MMcf during 2012 as compared to 2011, while oil volumes remained consistent between periods. Gas volume decreases in 2012 were primarily related to normal field production decline. Partially offsetting this gas volume decline were 2012 production increases related to (i) the resolution of pressure issues at a gas pipeline sales point in Oklahoma which negatively impacted gas production during 2011, (ii) recovery from Mississippi River flooding which hampered gas production in Louisiana during the third quarter of 2011, and (iii) three recently drilled gas wells that came on line during the last twelve months. Oil sales volumes remained relatively consistent between periods primarily due to four recently drilled oil wells that came on line during the last twelve months, as well as workover activity that resulted in increased production. These positive effects on oil production were largely offset by normal field production decline. In the December 31, 2012 reserve report, natural gas production attributable to the underlying properties is estimated to decline at rates ranging from 11% to 13% annually from 2013 through the estimated June 30, 2015 NPI termination date, while oil production is estimated to decline at approximately 9% annually over this same time period.


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Lease Operating Expenses. Lease operating expenses ("LOE") increased $3.9 million or 15% during 2012 compared to 2011. This increase in lease operating expenses during 2012 was primarily due to an increase of $3.8 million in the cost of oilfield goods and services, a $0.5 million increase in operating costs charged to wells that are not operated by Whiting, and $0.4 million in higher labor costs on Whiting-operated properties. These increases were partially offset by a $0.8 million decrease in plug and abandonment charges between periods. The increase in overall LOE coupled with the decrease in overall production volumes between periods resulted in an increase in LOE on a per BOE basis of 17%, from $20.44 in 2011 to $23.99 in 2012.

Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues before the effects of hedging. Tax credits and exemptions allowed in the various taxing jurisdictions are generally utilized to their potential. Production taxes during 2012 decreased $0.5 million or 10% compared to 2011, and production taxes as a percent of oil and gas revenues also declined between periods, from 7.3% in 2011 to 6.8% in 2012. This decrease was primarily related to certain production tax refunds received in the third quarter of 2012.

Cash Settlements on Commodity Derivatives. In connection with Whiting's conveyance of the net profits interest to the Trust, Whiting entered into certain costless collar hedge contracts in order to reduce the Trust's exposure to commodity price volatility. If current market prices are lower than a collar's price floor when the cash settlement amount is calculated, Whiting receives cash proceeds from the contract counterparty. Conversely, if current market prices are higher than a collar's price ceiling when the cash settlement amount is calculated, Whiting is required to pay the contract counterparty.

Cash settlements relating to these hedges resulted in a gain of $5.9 million for the year ended December 31, 2012, which had the effect of increasing the average price of natural gas by $2.12 per Mcf for that period, and cash settlements relating to these hedges resulted in a gain of $4.5 million for the year ended December 31, 2011, which had the effect of increasing the average price of natural gas by $1.51 per Mcf for that period. As a result, the total net price of natural gas of $5.28 per Mcf and $5.63 per Mcf that the Trust received for 2012 and 2011, respectively, included premiums of 40% and 27%, respectively, related to the effects of hedging for those same periods. However, all hedges and their related pricing impacts terminated as of December 31, 2012, while the Trust's oil and gas reserves are currently projected to terminate in June 2015 based on the Trust's 2012 reserve report. Therefore, no commodity price hedges will be in effect beginning January 1, 2013 through Trust termination to reduce the Trust's exposure to oil and natural gas price volatility.

General and Administrative Expenses. For the year ended December 31, 2012, the Trust's general and administrative expenses increased by $0.1 million as compared to 2011 due to differences in timing as to when certain administrative invoices were received and paid by the


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Trustee. Certain invoices for annual services provided by auditors and tax consultants were paid during the year ended December 31, 2012, and these recurring invoices were not similarly paid during the same 2011 reporting period.

Distributable Income. For the year ended December 31, 2012, the Trust's distributable income was $36.7 million and was based on income from net profits interest of $37.9 million, which has been reduced by Trust general and administrative costs of $0.8 million and Montana state income tax withholdings of $0.3 million, and adjusted for changes in Trust cash reserves. This compares to distributable income of $40.9 million during 2011, which was based on income from net profits interest of $41.9 million that has been reduced by $0.7 million for Trust administrative expenses and $0.3 million in Montana state income tax withholdings, and adjusted for changes in Trust cash reserves.

Comparison of Results of the Trust for the Years Ended December 31, 2011 and 2010

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 cash settlements on commodity derivatives as follows:

Revenues. Oil and natural gas revenues increased $6.3 million or 9% in 2011 compared to 2010. Revenues are a function of oil and natural gas sales prices and production volumes sold. The increase in revenue between periods was due to higher sales prices realized for crude oil in 2011, which effect was partially offset by lower sales prices realized for natural gas and lower oil and natural gas production volumes between periods. The average price for oil before the effects of hedging increased 23% between periods, while the average price for natural gas before the effects of hedging decreased 3%. Oil volumes decreased 5% or 44 MBOE, and gas volumes decreased 12% or 388 MMcf during 2011 as compared to 2010. Both of these volume decreases were primarily due to normal field production decline. In the December 31, 2012 reserve report, natural gas production attributable to the underlying properties is estimated to decline at rates ranging from 11% to 13% annually from 2013 through the estimated June 30, 2015 NPI termination date, while oil production is estimated to decline at approximately 9% annually over this same time period.

Lease Operating Expenses. Lease operating expenses increased $1.9 million or 8% during 2011 compared to 2010, primarily due to a $1.3 million increase in workover activity and a $0.8 million increase in operating costs charged to wells that are not operated by


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Whiting. These increases were partially offset by various cost declines amounting to $0.2 million that were generally associated with lower 2011 production levels. The increase in overall LOE coupled with the decrease in overall production volumes between periods resulted in an increase in LOE on a per BOE basis of 18%, from $17.39 in 2010 to $20.44 in 2011.

Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues before the effects of hedging. Tax credits and exemptions allowed in the various taxing jurisdictions are generally utilized to their potential. Production taxes during 2011 increased $0.6 million or 13% compared to 2010, primarily due to higher oil sales between periods. Production taxes as a percent of oil and gas revenues for 2011 and 2010 remained relatively constant at 7.3% and 7.1%, respectively.

Cash Settlements on Commodity Derivatives. In connection with Whiting's conveyance of the net profits interest to the Trust, Whiting entered into certain costless collar hedge contracts in order to reduce the Trust's exposure to commodity price volatility. If current market prices are lower than a collar's price floor when the cash settlement amount is calculated, Whiting receives cash proceeds from the contract counterparty. Conversely, if current market prices are higher than a collar's price ceiling when the cash settlement amount is calculated, Whiting is required to pay the contract counterparty.

Cash settlements relating to these hedges resulted in a gain of $4.5 million for the year ended December 31, 2011, which had the effect of increasing the average price of natural gas by $1.51 per Mcf for that period, and cash settlements relating to these hedges resulted in a gain of $4.3 million for the year ended December 31, 2010, which had the effect of increasing average prices by $0.25 per Bbl of oil and $1.23 per Mcf of natural gas for that period. As a result, the total net price of natural gas of $5.63 per Mcf and $5.49 per Mcf that the Trust received for 2011 and 2010, respectively, included a premium of 27% and 22%, respectively, related to the effects of hedging for those same periods. However, all hedges and their related pricing impacts terminated as of December 31, 2012, while the Trust's oil and gas reserves are currently projected to terminate in June 2015 based on the Trust's 2012 reserve report. Therefore, no commodity price hedges will be in effect beginning January 1, 2013 through Trust termination to reduce the Trust's exposure to oil and natural gas price volatility.

General and Administrative Expenses. For the year ended December 31, 2011, the Trust's general and administrative expenses decreased by $0.1 million as compared to 2010 due to differences in timing as to when certain administrative invoices were received and paid by the Trustee.

Distributable Income. For the year ended December 31, 2011, the Trust's distributable income was $40.9 million and was based on income from net profits interest of $41.9 million, which has been reduced by Trust general and administrative costs of $0.7 million and Montana state income tax withholdings of $0.3 million, and adjusted for changes in Trust cash reserves. This compares to distributable income of $37.4 million during 2010, which was based on income


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from net profits interest of $38.4 million that has been reduced by $0.9 million of Trust administrative expenses and $0.2 million in Montana state income tax withholdings, and adjusted for changes in Trust cash reserves.

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 Trust's 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 Trustee's 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 Trust's 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 Trust's 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".

Although capital expenditures for the testing, drilling, completion, equipping, plugging back or recompletion of any well that is a part of the underlying properties cannot be deducted from gross proceeds pursuant to the terms of the conveyance agreement, Whiting incurred capital expenditures of $6.8 million on the underlying properties during 2012, compared to $1.8 million in 2011 and $1.0 million in 2010. Such expenditures were not deducted from gross proceeds or Trust distributions, but they may have the effect of ultimately accelerating the receipt of NPI net proceeds and thereby benefiting the Trust unitholders by accelerating their return on investment. The Trust cannot provide any assurance that this will continue to occur or that future capital expenditures will be consistent with historical levels.

On February 8, 2011, Whiting established a $1.0 million letter of credit for the Trustee in order 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.


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The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust's liquidity or the availability of capital resources.

Off-Balance Sheet Arrangements

The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.

Contractual Obligations

The following table summarizes the Trust's obligations and commitments as of
December 31, 2012 to make future payments during the specified time periods:



                                                                  Payments Due by Period
Contractual Obligations                          Total             2013             2014           2015(d)
Delaware Trustee fees (a)                     $   10,500       $    3,500       $    3,500       $    3,500
Trustee administrative service fees (b)          400,000          160,000          160,000           80,000
Whiting administrative service fees (c)          500,000          200,000          200,000          100,000

Total                                         $  910,500       $  363,500       $  363,500       $  183,500

(a) Pursuant to the terms of the Trust agreement, the Trust is obligated to pay the Delaware Trustee a fee of $3,500 per year.

(b) Pursuant to the terms of the Trust agreement, the Trust is obligated to pay the Trustee an administrative fee of $160,000 per year.

(c) Pursuant to the terms of the administrative services agreement with Whiting, . . .

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