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HGT > SEC Filings for HGT > Form 10-Q on 5-Nov-2012All Recent SEC Filings

Show all filings for HUGOTON ROYALTY TRUST | Request a Trial to NEW EDGAR Online Pro

Form 10-Q for HUGOTON ROYALTY TRUST


5-Nov-2012

Quarterly Report


Item 2. Trustee's Discussion and Analysis.

The following discussion should be read in conjunction with the trustee's discussion and analysis contained in the trust's 2011 Annual Report on Form 10-K, as well as the condensed financial statements and notes thereto included in this Quarterly Report on Form 10-Q. 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 trust's web site at www.hugotontrust.com.

Distributable Income

Quarter

For the quarter ended September 30, 2012, net profits income was $3,131,255, as compared to $15,477,314 for third quarter 2011. This 80% decrease in net profits income is primarily the result of lower gas and oil prices ($10.4 million) and the Fankhouser settlement deduction in September 2012 ($1.7 million). See "Net Profits Income" on following page.


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After adding interest income of $87 and deducting administration expense of $982,022, distributable income for the quarter ended September 30, 2012 was $2,149,320, or $0.053733 per unit of beneficial interest. Administration expense for the quarter increased $837,713 as compared to the prior year quarter, $800,000 of which the trustee has reserved for legal expenses regarding the Fankhouser class action settlement. For third quarter 2011, distributable income was $15,333,360, or $0.383334 per unit. Distributions to unitholders for the quarter ended September 30, 2012 were:

                                                         Distribution
                 Record Date          Payment Date         per Unit
              July 31, 2012        August 14, 2012      $     0.034537
              August 31, 2012      September 17, 2012         0.013697
              September 28, 2012   October 15, 2012           0.005499

                                                        $     0.053733

Nine Months

For the nine months ended September 30, 2012, net profits income was $20,161,103 compared with $43,359,342 for the same 2011 period. This 54% decrease in net profits income is primarily the result of lower gas prices ($19.3 million), decreased oil and gas production ($4.8 million) and the Fankhouser settlement deduction in September 2012 ($1.7 million), partially offset by lower development costs ($2.2 million). See "Net Profits Income" below.

After adding interest income of $456 and deducting administration expense of $1,624,959, distributable income for the nine months ended September 30, 2012 was $18,536,600, or $0.463415 per unit of beneficial interest. Administration expense for the nine months ended September 30, 2012 increased $940,926 as compared with the same 2011 period, $900,000 of which the trustee has reserved for legal expenses regarding the Fankhouser class action settlement. For the nine months ended September 30, 2011, distributable income was $42,676,120, or $1.066903 per unit.

Net Profits Income

Net profits income is recorded when received by the trust, which is the month following receipt by XTO Energy, and generally two months after oil and gas production. Net profits income is generally affected by three major factors:

oil and gas sales volumes,

oil and gas sales prices, and

costs deducted in the calculation of net profits income.


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The following is a summary of the calculation of net profits income received by the trust:

                                              Three Months                                               Nine Months
                                         Ended September 30 (a)              Increase               Ended September 30 (a)              Increase
                                        2012                2011            (Decrease)             2012                2011            (Decrease)
Sales Volumes
Gas (Mcf) (b)
Underlying properties                   5,019,155          5,516,991                 (9 %)        15,126,599         16,452,271                 (8 %)
Average per day                            54,556             59,967                 (9 %)            55,207             60,265                 (8 %)
Net profits interests                     859,181          2,839,604                (70 %)         4,666,187          8,108,961                (42 %)

Oil (Bbls) (b)
Underlying properties                      58,903             58,527                  1 %            172,884            190,712                 (9 %)
Average per day                               640                636                  1 %                631                699                (10 %)
Net profits interests                      12,380             31,574                (61 %)            60,929             99,334                (39 %)

Average Sales Prices
Gas (per Mcf)                       $        2.74       $       4.96                (45 %)     $        3.27       $       4.74                (31 %)
Oil (per Bbl)                       $       82.01       $      95.00                (14 %)     $       92.71       $      92.19                  1 %

Revenues
Gas sales                           $  13,766,357       $ 27,374,742                (50 %)     $  49,531,262       $ 77,966,678                (36 %)
Oil sales                               4,830,830          5,559,851                (13 %)        16,028,348         17,581,921                 (9 %)

Total Revenues                         18,597,187         32,934,593                (44 %)        65,559,610         95,548,599                (31 %)

Costs
Taxes, transportation and other         2,476,472          3,514,793                (30 %)         8,097,462         10,279,464                (21 %)
Production expense                      5,736,542          5,173,918                 11 %         17,343,151         15,656,008                 11 %
Development costs (c)                   1,500,000          2,200,000                (32 %)         4,500,000          7,300,000                (38 %)
Overhead                                2,828,980          2,699,240                  5 %          8,276,494          8,113,950                  2 %
Legal Expense (d)                      35,601,400                  -                  -           35,601,400                  -                  -
Excess Costs (e)                      (33,460,276 )                -                  -          (33,460,276 )                -                  -

Total Costs                            14,683,118         13,587,951                  8 %         40,358,231         41,349,422                 (2 %)

Net Proceeds                            3,914,069         19,346,642                (80 %)        25,201,379         54,199,177                (54 %)

Net Profits Percentage                         80 %               80 %                                    80 %               80 %

Net Profits Income                  $   3,131,255       $ 15,477,314                (80 %)     $  20,161,103       $ 43,359,342                (54 %)

(a) Because of the two-month interval between time of production and receipt of net profits income by the trust, (1) oil and gas sales for the quarter ended September 30 generally represent production for the period May through July and (2) oil and gas sales for the nine months ended September 30 generally represent production for the period November through July.

(b) Oil and gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and gas prices and the total amount of production expense and development costs. As product prices change, the trust's share of the production volumes is impacted as the quantity of production to cover expenses in reaching the net profits break-even level changes inversely with price. As such, the underlying property production volume changes may not correlate with the trust's net profit share of those volumes in any given period. Therefore, comparative discussion of oil and gas sales volumes is based on the underlying properties.

(c) See Note 2 to Condensed Financial Statements.

(d) See Note 5 to Condensed Financial Statements.

(e) See Note 6 to Condensed Financial Statements.


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The following are explanations of significant variances on the underlying properties from third quarter 2011 to third quarter 2012 and from the first nine months of 2011 to the comparable period in 2012:

Sales Volumes

Gas

Gas sales volumes decreased 9% for third quarter and 8% for the nine-month period as compared with the same 2011 periods primarily because of natural production decline.

Oil

Oil sales volumes increased 1% for third quarter 2012 as compared with the same 2011 period primarily because of the timing of cash receipts, partially offset by natural production decline. Oil sales volumes decreased 9% for the first nine months of 2012 as compared with the same 2011 period primarily because of natural production decline.

The estimated rate of natural production decline on the underlying oil and gas properties is approximately 6% to 8% a year.

Sales Prices

Gas

The third quarter 2012 average gas price was $2.74 per Mcf, a 45% decrease from the third quarter 2011 average gas price of $4.96 per Mcf. For the nine-month period, the average gas price decreased 31% to $3.27 per Mcf in 2012 from $4.74 per Mcf in 2011. Natural gas prices are affected by the level of North American production, weather, crude oil and natural gas liquids prices, the U.S. economy, storage levels and import levels of liquefied natural gas. Natural gas prices are expected to remain volatile. The third quarter 2012 gas price is primarily related to production from May through July 2012, when the average NYMEX price was $2.41 per MMBtu. The average NYMEX price for August and September 2012 was $2.82 per MMBtu. At October 12, 2012, the average NYMEX futures price for the following twelve months was $3.94 per MMBtu.

Oil

The third quarter 2012 average oil price was $82.01 per Bbl, a 14% decrease from the third quarter 2011 average oil price of $95.00 per Bbl. The year-to-date average oil price increased 1% to $92.71 per Bbl in 2012 from $92.19 per Bbl in 2011. Oil prices are expected to remain volatile. The third quarter 2012 oil price is primarily related to production from May through July 2012, when the average NYMEX price was $88.33 per Bbl. The average NYMEX price for August and September 2012 was $94.52 per Bbl. At October 12, 2012, the average NYMEX futures price for the following twelve months was $93.64 per Bbl.

Costs

Taxes, Transportation and Other

Taxes, transportation and other decreased 30% for the quarter and 21% for the nine-month period primarily because of decreased gas production taxes and other deductions related to lower gas revenues, partially offset by increased property tax valuations.


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Production Expense

Production expense increased 11% for the quarter primarily because of increased labor costs and marketing and economic rebates included in 2011, partially offset by decreased fuel costs. Production expense increased 11% for the nine-month period primarily because of increased labor and maintenance costs and marketing and economic rebates included in 2011, partially offset by decreased insurance costs.

Development Costs

Development costs deducted in the calculation of net profits income are based on the development budget. These development costs decreased 32% for the third quarter and 38% for the nine-month period primarily because of decreased development activity.

As of December 31, 2011, cumulative budgeted costs exceeded cumulative actual costs by approximately $2.4 million. In calculating net profits income for the quarter ended September 30, 2012, XTO Energy deducted budgeted development costs of $1.5 million for the quarter and $4.5 million for the nine-month period. After considering actual development costs of $2.0 million for the quarter and $7.9 million for the nine-month period, cumulative actual costs exceeded budgeted costs deducted by approximately $1.0 million at September 30, 2012.

XTO Energy has advised the trustee that revised total 2012 budgeted development costs for the underlying properties are between $6 million and $8 million. The 2012 budget year generally coincides with the trust distribution months from April 2012 through March 2013. The monthly development cost deduction will be reevaluated by XTO Energy and revised as necessary, based on the 2012 budget and the timing and amount of actual expenditures. See Note 2 to Condensed Financial Statements.

Excess Costs

XTO advised the trustee that lower gas prices and increased production expenses related to the timing of cash disbursements caused costs to exceed revenues by $114,245 ($91,396 net to the trust) on properties underlying the Wyoming net profits interests in July 2012. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO advised the trustee that increased gas prices and decreased production expenses led to the full recovery of excess costs, plus accrued interest of $314 ($251 net to the trust) in August 2012.

XTO advised the trustee in September 2012 that it deducted $35,601,400 ($28,481,120 net to the trust) related to the Fankhouser settlement. The settlement deduction caused costs to exceed revenues by $27,235,464 ($21,788,371 net to the trust) on properties underlying the Oklahoma net profits interests and by $6,225,126 ($4,980,101 net to the trust) on properties underlying the Kansas net profits interests. However, these excess costs did not reduce net proceeds from the remaining conveyance. See Note 5 to Condensed Financial Statements.

Contingencies

XTO Energy has entered into a tentative settlement agreement in connection with certain litigation that is anticipated to adversely affect the net proceeds of the trust from Oklahoma and Kansas. See Note 5 to Condensed Financial Statements.

Several states have enacted legislation requiring state income tax withholding from nonresident recipients of oil and gas proceeds. After consultation with its tax counsel, the trustee believes that it is not required to withhold on payments made to the unitholders. However, regulations are subject to change by the various


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states, which could change this conclusion. Should amounts be withheld on payments made to the trust or the unitholders, distributions to the unitholders would be reduced by the required amount, subject to the filing of a claim for refund by the trust or unitholders for such amount.

Forward-Looking Statements

Statements in this report relating to future plans, predictions, events or conditions are forward-looking statements. All statements other than statements of historical fact included in this Form 10-Q, including, without limitation, statements regarding the net profits interests, underlying properties, development activities, annual and monthly development, production and other costs and expenses, monthly development cost deductions, oil and gas prices and differentials to NYMEX prices, supply levels, future drilling, workover and restimulation plans, the outcome of litigation and impact on trust proceeds, distributions to unitholders and industry and market conditions, are forward-looking statements that are subject to risks and uncertainties which are detailed in Part I, Item 1A of the trust's Annual Report on Form 10-K for the year ended December 31, 2011, which is incorporated by this reference as though fully set forth herein. XTO Energy and the trustee assume no duty to update these statements as of any future date.

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