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Filed pursuant to Rule 424(b)(3)
Registration No. 333-88282
DORCHESTER MINERALS, L.P.
3738
OAK LAWN, SUITE 300
DALLAS, TEXAS 75219
SUPPLEMENT NO. 1 TO
PROXY STATEMENT/PROSPECTUS DATED OCTOBER 30, 2002
THE DATE OF THIS SUPPLEMENT NO. 1 IS DECEMBER13, 2002
Dear Limited Partners,
The following information supplements the
proxy statement/prospectus dated October 30, 2002, of Dorchester Minerals, L.P., a Delaware limited partnership, by which the general partners of Dorchester Hugoton, Ltd., Republic Royalty Company and Spinnaker Royalty Company, L.P. are soliciting
proxies and written consents, as applicable, in connection with the special meetings of the limited partners of Dorchester Hugoton and Spinnaker and in lieu of a meeting for Republic. The purpose of the special meetings and written consent is to
vote upon the combination of the businesses and properties of Dorchester Hugoton, Republic and Spinnaker into Dorchester Minerals, which will result in the limited partners of the combining partnerships receiving common units of Dorchester Minerals.
This supplement includes financial and other information that updates information in the proxy
statement/prospectus. You should carefully consider the information in this supplement together with the information in the proxy statement/prospectus.
This supplement does not change the proposals previously submitted for your approval. If you have already properly completed and returned a proxy or consent card, as applicable, it will continue to be
valid. If you are a Dorchester Hugoton limited partner, you may obtain more information on voting by calling Dorchester Hugoton’s information agent, D.F. King & Co. at (800) 290-6431. In addition, all of the limited partners of Dorchester
Hugoton, Republic and Spinnaker may contact the general partners of their respective partnerships for more information.
The combination will not occur unless the limited partners of each of the combining partnerships approve the combination. If you fail to vote by proxy or consent card, as applicable, or in person, it will have the same effect as a
vote against the transaction. If you have not already done so, please vote by completing and returning your proxy or consent card, as applicable, so that your vote maybe counted. As discussed in the proxy statement/prospectus, we recommend that you
vote FOR the combination.
Sincerely,
| P.A. Peak, Inc. |
SAM Partners, Ltd. | |
| James E. Raley, Inc. |
Vaughn Petroleum, Ltd. | |
| General Partners of |
General Partners of | |
| Dorchester Hugoton |
Republic |
Smith Allen Oil &
Gas, Inc.
General Partner of
Spinnaker
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this supplement and the accompanying supplements are truthful or complete. Any representation to the contrary is a criminal offense.
Please see the sections entitled “Summary—Risk Factors” beginning on page 5 and “Risk Factors” beginning on
page 16 of the proxy statement/prospectus for a discussion of the risks involved in the combination.
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GENERAL
As previously announced, the special meeting of depositary receipt holders of Dorchester Hugoton will be held at 10:00 a.m. on December 30, 2002 at the Holiday Inn at 11350 LBJ Freeway at Jupiter Road in Dallas, Texas to
consider and vote upon the proposed combination with Republic and Spinnaker into Dorchester Minerals, L. P., a new publicly traded limited partnership. The special meeting of limited partners of Spinnaker will be held at 11:00 a.m. on December 30,
2002 at the Holiday Inn at 11350 LBJ Freeway at Jupiter Road in Dallas, Texas to consider and vote upon the combination. Republic’s limited partners will act by written consent in lieu of a special meeting of limited partners.
If the combination is approved by more than 50% of the depositary receipt holders of Dorchester Hugoton, all of the limited
partners of Republic and limited partners of Spinnaker holding at least 85.9883% of the sharing percentages of Spinnaker, and if all other conditions to the combination have been satisfied by December 31, 2002, then it is anticipated that the
combination will close immediately after December 31, 2002. Please see “The Combination Agreement—Conditions” on page 71 of the prospectus for a description of the conditions to the combination.
If the combination closing occurs in the anticipated manner, Dorchester Hugoton expects to distribute its remaining cash, if any, and our
common units received in the combination to its general partners and to its non-dissenting depositary receipt holders who are depositary receipt holders at the close of business on December 31, 2002 as a liquidating distribution. Because of the
combination, there will not be an “ex-dividend” date for this liquidating distribution as there would be for a regular distribution. If the closing occurs in the anticipated manner and the liquidating distribution is subsequently made,
Dorchester Hugoton anticipates that the liquidating distribution will be reported for tax purposes on a 2002 final K-1 tax statement from Dorchester Hugoton. The actual payment of the liquidating distribution will occur in 2003 upon each depositary
receipt holder’s exchange of Dorchester Hugoton’s depositary receipts for our common units. Dorchester Hugoton expects that depositary receipt holders whose depositary receipts are held for them by a broker or similar custodian should
receive their share of any liquidating distribution in January 2003 directly from their broker or custodian.
Should the combination close, Dorchester Hugoton now anticipates that the total amount of the cash portion of the liquidating distribution will be slightly more than 99% of Dorchester Hugoton’s remaining cash at closing. Based
on the financial information contained in this supplement, Dorchester Hugoton’s cash available on September 30, 2002 was approximately $18 million. Dorchester Hugoton’s remaining cash, if any, that will be included in the liquidating
distribution will be increased by subsequent net cash flows and the proceeds of the sale of 128,000 shares of ExxonMobil common stock, which will be sold prior to the closing of the combination, and will be reduced by payments under Dorchester
Hugoton’s severance plan (estimated to be $2.7 million), combination costs for which Dorchester Hugoton is responsible, payments to depositary receipt holders exercising dissenters’ rights, if any, and amounts transferred to us and
Dorchester Minerals Operating LP to fund certain obligations of Dorchester Hugoton that we and it will assume in the combination.
OUR INITIAL QUARTERLY DISTRIBUTION
After closing and in the regular ongoing course of our
business, we will distribute to our limited partners and general partner according to their respective interests, within 45 days of the end of each fiscal quarter, an amount equal to all “available cash” with respect to that quarter.
Available cash means all cash and cash equivalents on hand at the end of that quarter, less any amount of cash reserves that our general partner determines is necessary or appropriate to provide for the conduct of its business or to comply with
applicable law or agreements or obligations to which we may be subject. Due to the timing of our receipt of production revenues, our initial quarterly distribution will generally reflect three months of production from the royalty properties and two
months of production from properties underlying the Operating ORRIs. This is a one-time occurrence associated with the creation of the Operating ORRIs and the delay in our receipt of revenue. Subsequent quarterly distributions will generally reflect
three months of production from the royalty properties and the properties underlying the Operating ORRIs. Our initial quarterly distribution will also reflect payment of costs and expenses for which we are responsible that will be incurred and paid
upon the successful consummation of the combination. These costs include Nasdaq listing fees, director and officer insurance premiums, recording and filing fees and legal expenses associated with the closing of the combination.
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THIRD QUARTER RESULTS OF THE COMBINING PARTNERSHIPS
The following sets forth selected financial information and operating data and management’s discussion and analysis of financial condition and results of operations
for each of the combining partnerships for the period ended September 30, 2002. The unaudited financial statements of each combining partnership for the period ended September 30, 2002 are included in the Appendix to this supplement.
INFORMATION CONCERNING DORCHESTER HUGOTON
Selected Financial and Operating Data
The following table sets forth a summary of selected
unaudited financial information and operating data for Dorchester Hugoton for the periods indicated. It should be read in conjunction with the financial statements and related notes included in the Appendix to this document.
| As of and for the Nine Months
Ended September 30, | |||||||
| 2002 |
2001 | ||||||
| (in thousands except per unit and as otherwise indicated) | |||||||
| Total operating revenues |
$ |
12,857 |
|
$ |
23,121 | ||
| Net earnings |
$ |
7,215 |
|
$ |
17,099 | ||
| Net earnings per unit |
$ |
0.66 |
|
$ |
1.57 | ||
| Cash distributions(1) |
$ |
8,791 |
|
$ |
9,876 | ||
| Book value per unit |
$ |
3.59 |
|
$ |
4.03 | ||
| Net cash provided by operating activities |
$ |
8,597 |
|
$ |
19,280 | ||
| Total assets at book value |
$ |
38,969 |
|
$ |
43,695 | ||
| Cash distributions per unit(1) |
$ |
.81 |
|
$ |
.91 | ||
| Cash/cash equivalents |
$ |
18,111 |
|
$ |
19,701 | ||
| Increase (decrease) in cash/cash equivalents |
$ |
(328 |
) |
$ |
3,934 | ||
| Long-term debt, including current portion |
$ |
— |
|
$ |
— | ||
| Total liabilities |
$ |
4,218 |
|
$ |
4,668 | ||
| General partners’ equity |
$ |
255 |
|
$ |
288 | ||
| Unitholders’ equity |
$ |
32,930 |
|
$ |
36,213 | ||
| Accumulated other comprehensive income |
$ |
1,566 |
|
$ |
2,526 | ||
| Total partnership capital |
$ |
34,751 |
|
$ |
39,027 | ||
(1) |
Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return
of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distributions may be deemed to be a return of capital. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion is intended to assist in understanding Dorchester Hugoton’s financial position and results of operations for the nine months ended September
30, 2002 and 2001. You should refer to Dorchester Hugoton’s financial statements and the notes to the financial statements included in the Appendix to this supplement in conjunction with this discussion.
Overview
Dorchester Hugoton’s business operations consist of producing, gathering and selling natural gas from the long-established Hugoton gas field in Oklahoma and Kansas. Dorchester Hugoton distributes a large proportion of
its net cash flow each year. It has not engaged in exploration activities and has not engaged in development
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activities except to a very limited extent with respect to replacement or improvement of its existing wells. Its cash flow from operations has historically been sufficient to fund its cash and
capital expenditure requirements, and, while it previously maintained a revolving credit arrangement with a bank, borrowings since January 1, 1998 have been minimal.
Dorchester Hugoton’s period to period changes in net earnings and cash flows from operating activities are principally determined by changes in natural gas sales
volumes and gas prices. Dorchester Hugoton’s portion of gas sales volumes (not reduced for the Oklahoma production payment, where applicable) and weighted average sales prices for the periods indicated were:
| Nine Months Ended September 30, | ||||||
| 2002 |
2001 | |||||
| Sales Volumes (MMcf): |
||||||
| Oklahoma |
|
3,660 |
|
3,850 | ||
| Kansas |
|
646 |
|
739 | ||
| |
|
|
| |||
| Total |
|
4,306 |
|
4,589 | ||
| |
|
|
| |||
| Weighted Average Sales Prices ($/Mcf): |
||||||
| Oklahoma |
$ |
2.98 |
$ |
5.12 | ||
| Kansas |
$ |
2.86 |
$ |
5.19 | ||
| Overall Weighted Average Sales Price |
$ |
2.96 |
$ |
5.13 | ||
It is expected that net operating revenues for 2002 and future
years will be benefited by Dorchester Hugoton’s acquisition for $5,270,000 in 2001 of a production payment, which had reduced its net operating income and cash flow in prior years. The benefit will be partially offset by increased depletion.
Since future payments depend upon future gas prices, the amount of future benefit is not reasonably quantifiable. During the twelve month periods ending March 1, 2001, 2000, and 1999, the production payment to others has been approximately
$1,701,000, $730,000, and $646,000, respectively.
Nine Months Ended September 30, 2002 Compared with the
Nine Months Ended September 30, 2001
As shown in the table above, Oklahoma nine month 2002 gas sales
volumes were 5% lower than the same period of 2001. Oklahoma volumes were influenced by reduced gas pipeline receipts in 2002 because of an explosion unrelated to Dorchester Hugoton and natural reservoir decline. Kansas nine month 2002 gas sales
volumes were 13% lower than the same period of 2001 as a result of state well testing and natural reservoir decline.
Natural gas weighted average sales prices in the first nine months of 2002 were down 42% compared to the same period of 2001 due to lower market prices. The significantly lower gas prices and lower gas volumes caused net operating
revenues to decrease compared to the first nine months of 2001.
Operating costs during the first nine months of
2002 were lower than the same period of 2001 primarily due to lower production taxes associated with lower natural gas revenues which were partially offset by an increase in depletion costs resulting from the purchase of the Oklahoma production
payment during the second quarter of 2001. Legal and other costs associated with the proposed combination with Republic and Spinnaker increased $259,000 compared to the same period of last year, while investment income was down $465,000 due to
reduced interest rates in the marketplace.
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Liquidity and Capital Resources
On July 19, 1994, Dorchester Hugoton entered into a $15,000,000 unsecured revolving credit facility with Bank One, Texas, NA, which would
have expired July 31, 2002. The borrowing base was $6,000,000, which was to be reevaluated by the bank at least annually. As of December 31, 2001, no letters of credit were issued under the credit facility and the amount borrowed was $100,000.
Dorchester Hugoton repaid its borrowings on June 4, 2002 and terminated the agreement.
Cash flows from operating
activities remain sufficient to meet Dorchester Hugoton’s anticipated costs and expenses. Expenses, including combination-related costs, were 31.3% and 19.4% of net operating revenues for the nine months ended September 30, 2002 and 2001,
respectively. Capital expenditures, including the acquisition of the Oklahoma production payment in 2001, were 1.4% and 23.8% of net operating revenues for the nine months ended September 30, 2002 and 2001, respectively. Dorchester Hugoton has no
current outstanding material commitments for capital expenditures. Cash and cash equivalents at September 30, 2002 and 2001 were $18,111,000 and $19,701,000, respectively.
Dorchester Hugoton does not currently anticipate drilling additional wells as a working interest owner in the Fort Riley zone, the Council Grove formation or elsewhere, but
successful activities by others in these formations could prompt a reevaluation by Dorchester Hugoton. Any such drilling is estimated to require $250,000 to $300,000 per well. Dorchester Hugoton anticipates continuing additional fracture treating
but is unable to predict the cost until additional engineering studies are done.
Dorchester Hugoton anticipates
normal gradual increases in repairs to its Oklahoma gas compression and dehydration facility and gradual increases in Oklahoma field operating costs and expenses as repairs to its 50-year-old pipelines and gas wells become more frequent and as
pressures decline. Dorchester Hugoton does not anticipate significant replacement of these items at this time. However, Dorchester Hugoton believes rental field compression units installed at various locations on its Oklahoma gas gathering pipelines
may become necessary in 2003 because of lower pressures. The cost of such additional compression could require from $400,000 to $600,000 in capital and require $350,000 to $400,000 per year additional operating costs (primarily compressor rental).
While it is believed that the benefits of such compression will more than exceed cost and recover capital, neither the timing of such a project nor the increased gas production are currently predictable.
In 1998, Oklahoma removed production quantity restrictions in the Guymon-Hugoton field, and did not address efforts by third parties to
persuade Oklahoma to permit infill drilling in the Guymon-Hugoton field. Both infill drilling and removal of production limits could require considerable capital expenditures. The outcome and the cost of such activities are unpredictable. No
additional compression has been installed that affects Dorchester Hugoton’s wells since 2000 by operators on adjoining acreage resulting from the relaxed production rules. Such installations by others could require expenditures by Dorchester
Hugoton to stay competitive with adjoining operators.
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INFORMATION CONCERNING REPUBLIC
Selected Combined Financial and Operating Information
The
following table presents a summary of selected unaudited combined financial information and operating data for Republic for the periods indicated, and assumes that the Republic reorganization has occurred. The combined financial information reflects
the combined operating results and financial condition of Republic and the Republic ORRIs. Intercompany amounts have been eliminated. It should be read in conjunction with the Republic and Republic ORRI financial statements and related notes
included in the Appendix to this document.
| Nine Months Ended September 30, |
|||||||
| 2002 |
2001 |
||||||
| (in thousands) |
|||||||
| Total operating revenues |
$ |
12,234 |
$ |
14,299 |
| ||
| Net earnings |
$ |
5,683 |
$ |
9,251 |
| ||
| Net earnings per unit (1) |
$ |
57 |
$ |
93 |
| ||
| Cash distributions (2) |
$ |
8,584 |
$ |
16,101 |
| ||
| Cash distributions per unit (1)(2) |
$ |
86 |
$ |
161 |
| ||
| Net cash provided by operating activities |
$ |
8,946 |
$ |
14,461 |
| ||
| Total assets at book value |
$ |
35,211 |
$ |
29,459 |
| ||
| Book value per unit (1) |
$ |
352 |
$ |
294 |
| ||
| Cash/cash equivalents |
$ |
1,000 |
$ |
667 |
| ||
| Increase (decrease) in cash/cash equivalents |
$ |
421 |
$ |
(1,239 |
) | ||
| Total liabilities |
$ |
4,675 |
$ |
3,126 |
| ||
| General partners’ equity(3) |
$ |
1,644 |
$ |
1,537 |
| ||
| Limited partners’ equity(3) |
$ |
28,892 |
$ |
24,796 |
| ||
| Partners’ equity |
$ |
30,536 |
$ |
26,333 |
| ||
(1) |
Republic’s equity structure is based on percentage interests. Per unit disclosures have been prepared on the basis that a unit represents a 1% partnership
interest. |
(2) |
Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return
of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distributions may be deemed to be a return of capital. |
(3) |
The information presented as general partners’ equity includes information with respect to the Affiliated Partnership, while limited partners’ equity
includes only information with respect to the Unaffiliated ORRI Owners. A portion of the Republic general partners’ interest will be converted to a limited partner interest in connection with the Republic reorganization. For the purpose of this
presentation, all interests of the Republic general partners have been included as general partners’ equity. |
Management’s Discussion and Analysis of Combined Financial Condition and Results of Operations
The following discussion is intended to assist the reader in understanding Republic’s combined financial position and results of operations for the nine months ended September 30, 2002 and 2001. This discussion assumes that the
Republic reorganization has occurred. See “The Combination—Preparatory Steps—Reorganization of Republic” beginning on page 65 of the proxy statement/prospectus for a discussion of the Republic reorganization. You should also
refer to Republic’s financial statements and the notes to the financial statements included in the Appendix to this supplement.
Overview
Republic’s business activities consist of the ownership and
administration of producing and nonproducing mineral, royalty, overriding royalty and leasehold interests located in 392 counties and parishes in 23 states. Republic owns and produces oil and natural gas reserves almost exclusively in the capacity
of a royalty owner. As a royalty owner, Republic’s involvement in the operation of producing properties in which it owns an interest is extremely limited and as such, Republic is a passive participant in these activities. In the instances in
which
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Republic owns the executive rights in nonproducing properties, it is generally able to negotiate certain terms and conditions governing the conduct of its lessees when leasing its interest to
third parties who may develop such properties. However, in the event production is established on those properties, Republic’s involvement in the operation of such properties is similarly limited and as such Republic becomes a passive
participant in such operations. Republic does not engage in oil and gas exploration, development and producing activities as an operator or working interest owner, and except in limited instances, does not bear any cost associated with activity on
properties in which it owns an interest. Republic distributes substantially all of its cash flow each year.
Republic’s year-to-year changes in net income and net cash flow from operations are principally determined by changes in oil and natural gas sales volumes and oil and natural gas prices. As a royalty owner, Republic essentially
has no control over the volumes of oil and natural gas produced and sold from properties in which it owns an interest. Republic’s net share of oil and natural gas sales volumes and the corresponding weighted average sales prices for the periods
indicated:
| Nine Months Ended September 30, | ||||
| 2002 |
2001 | |||
| Sales Volumes Oil (Bbls) |
189,963 |
213,768 | ||
| Gas (MMcf) |
1,457.4 |
2,016.3 | ||
| Weighted Average Price |
||||
| Oil ($/Bbl) |
22.54 |
26.13 | ||
| Gas ($/Mcf) |
2.95 |
5.07 | ||
Nine Months Ended September 30, 2002 Compared to the Nine
Months Ended September 30, 2001
Oil and natural gas sales volumes of 189,693 Bbls and 1,457.4 MMcf sold
during 2002 were 11% and 28% lower, respectively, than 213,768 Bbls and 2,016.3 MMcf sold during 2001. The decrease in oil and natural gas sales volumes were due to natural reservoir declines.
Weighted average oil sales prices of $22.54/Bbl during 2002 were 14% lower than $26.13/Bbl received in 2001 due to average marketplace prices and the effects of a
fixed price oil sales contract. Approximately 25% of Republic’s total net oil sales volumes were sold under fixed prices of $27.53/Bbl during 2001. Eliminating the effect of this contract results in a weighted average oil sales price of
$25.65/Bbl during 2001. This contract was still in effect as of September 30, 2001. Weighted average natural gas prices of $2.95/Mcf were 42% lower in 2002 than $5.07/Mcf received in 2001 due to changes in marketplace prices.
Lease bonus and delay rental income of $10,593 was 42% lower in 2002 than $18,171 received in 2001 due to reduced leasing
activity. Other income of $493,348 was 49% higher in 2002 than $330,470 received in 2001 due to non-recurring amounts received in 2002 attributable to litigation settlement proceeds and reduced interest earned on accumulated balances.
Oil and gas production taxes of $1,026,764 were 28% lower in 2002 than $1,428,718 paid in 2001 due primarily to lower
production revenue.
General and administrative expenses of $238,834 were 19% higher during 2002 than $200,892
paid in 2001 due primarily to increased rent and to salaries and benefits of employees of the general partners and their affiliates. General and administrative expense reflects general and administrative costs that are reimbursed to the general
partner in accordance with Republic’s partnership agreement.
Depletion expense of $2,770,011 was 16% higher
in 2002 than $2,393,191 recorded in 2001 due to accrued production volumes associated with the settlement of the Salinas litigation.
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Other operating costs of $2,455,857 were 293% higher in 2002 than $624,284 paid
in 2001 due to increased legal and professional expenses attributable to the proposed combination with Dorchester Hugoton and Spinnaker and to legal expenses and settlement costs associated with the settlement of the Salinas litigation.
As a result, total expenses of $6,550,381 during 2002 were 41% higher than $4,647,085 recorded in 2001, and net
income of $5,683,152 during 2002 was 39% lower than $9,250,884 recorded in 2001 due primarily to lower oil and natural gas sales prices.
Liquidity and Capital Resources
Republic’s only cash requirements are
the distributions pursuant to the Republic ORRIs and the payment of (a) oil and gas production and property taxes not otherwise deducted from gross production revenues, (b) operating expenses associated with the minor working interest properties not
otherwise deducted from gross production revenues and (c) general and administrative expenses incurred in its behalf and properly allocated in accordance with its partnership agreement. These cash requirements are funded with oil and natural gas
production revenues, lease bonus and delay rental income and nonrecurring income generated from other sources. Since the amounts distributable pursuant to the Republic ORRIs are, by definition, determined after the payment of all expenses actually
paid by the partnership, these payments do not represent obligations for which sufficient liquidity is at all times available. As a result, the only cash requirements that may create liquidity concerns for Republic are the payments of taxes and
expenses as detailed above. These expenses ranged between 11.5% and 18.9% of total revenues during 1999, 2000 and 2001. Since most of these expenses are dependent upon oil and natural gas prices and sales volumes, sufficient funds are anticipated to
be available at all times for payment thereof.
Republic is not liable for the payment of any exploration,
development or production costs, with certain limited exceptions, which are both individually and in the aggregate insignificant. Republic does not have any transactions, arrangements or other relationships that could materially affect the
partnership’s liquidity or the availability of capital resources. Republic had no obligations and commitments to make future contractual payments as of September 30, 2002, other than the September distribution payable to the Republic ORRI
Owners in October 2002, as reflected in the financial statements. Republic has not guaranteed the debt of any other party, nor does it have any other arrangements or relationships with other entities that could potentially result in unconsolidated
debt.
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INFORMATION CONCERNING SPINNAKER
Selected Financial and Operating Information
The following
table presents a summary of selected unaudited financial information and operating data for Spinnaker for the periods indicated. It should be read in conjunction with Spinnaker’s financial statements and related notes included in the Appendix
to this document.
| Nine Months Ended September 30, |
||||||||
| 2002 |
2001 |
|||||||
| (in thousands) |
||||||||
| Total operating revenues |
$ |
6,096 |
|
$ |
9,222 |
| ||
| Net earnings |
$ |
3,565 |
|
$ |
7,030 |
| ||
| Net earnings per unit (1)(2) |
$ |
36 |
|
$ |
70 |
| ||
| Cash distributions (2) |
$ |
4,490 |
|
$ |
10,138 |
| ||
| Cash distributions per unit (1) |
$ |
45 |
|
$ |
101 |
| ||
| Net cash provided by operating activities |
$ |
4,716 |
|
$ |
9,477 |
| ||
| Total assets at book value |
$ |
13,198 |
|
$ |
14,704 |
| ||
| Book value per unit (1) |
$ |
131 |
|
$ |
147 |
| ||
| Cash/cash equivalents |
$ |
597 |
|
$ |
388 |
| ||
| Increase (decrease) in cash/cash equivalents |
$ |
226 |
|
$ |
(661 |
) | ||
| Total liabilities |
$ |
268 |
|
$ |
489 |
| ||
| General partner’s equity |
$ |
(346 |
) |
$ |
(285 |
) | ||
| Limited partner’s equity |
$ |
13,276 |
|
$ |
14,499 |
| ||
| Partners’ equity |
$ |
12,930 |
|
$ |
14,214 |
| ||
(1) |
Spinnaker’s equity structure is based on percentage interests. Per unit disclosures have been prepared on the basis that a unit represents a 1% partnership
interest. |
(2) |
Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return
of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distributions may be deemed to be a return of capital. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion is intended to assist the reader in understanding Spinnaker’s financial position and results of operations for the nine months ended September
30, 2002 and 2001. You should refer to Spinnaker’s financial statements and the notes to the financial statements included in the Appendix to this supplement in conjunction with this discussion.
Overview
Spinnaker’s business activities consist of the ownership and administration of producing and nonproducing mineral, royalty, overriding royalty and leasehold interests located in 352 counties and parishes in 20 states.
Spinnaker owns and produces oil and natural gas reserves almost exclusively in the capacity of a royalty owner. As a royalty owner, Spinnaker’s involvement in the operation of producing properties in which it owns an interest is extremely
limited and as such, Spinnaker is a passive participant in these activities. In the instances in which Spinnaker owns the executive rights in nonproducing properties, it is generally able to negotiate certain terms and conditions governing the
conduct of its lessees when leasing its interest to third parties who may develop such properties. However, in the event production is established on those properties, Spinnaker’s involvement in the operation of such properties is similarly
limited and as such Spinnaker becomes a passive participant in such operations. Spinnaker does not engage in oil and gas exploration, development and producing activities as an operator or working interest owner, and except in limited instances,
does not bear any cost associated with activity on properties in which it owns an interest. Spinnaker distributes substantially all of its cash flow each year.
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Spinnaker’s year-to-year changes in net income, net cash flow from
operations and distributions to partners are principally determined by changes in oil and natural gas sales volumes and oil and natural gas prices. As a royalty owner, Spinnaker essentially has no control over the volumes of oil and natural gas
produced and sold from properties in which it owns an interest. Spinnaker’s net share of oil and natural gas sales volumes and the corresponding weighted average sales prices for the periods indicated were:
| Nine Months Ended September 30, | ||||
| 2002 |
2001 | |||
| Sales Volumes |
||||
| Oil (Bbls) |
58,383 |
63,332 | ||
| Gas (MMcf) |
1,759.6 |
1,691.4 | ||
| Weighted Average Price |
||||
| Oil ($/Bbl) |
21.00 |
25.61 | ||
| Gas ($/Mcf) |
2.52 |
4.99 | ||
Nine Months Ended September 30, 2002 Compared to the Nine
Months Ended September 30, 2001
Oil and natural gas sales volumes of 58,383 Bbls and 1,759.6 MMcf sold
during 2002 were 8% and 4% lower and higher, respectively, than 63,332 Bbls and 1,691.4 MMcf sold during 2001. The decrease in oil sales volume was due to natural reservoir declines. The increase in natural gas sales volume was due to receipt of
suspended funds attributable to several years of production from certain properties. Eliminating the effects of the receipt of these suspended funds results in natural gas sales volumes of 1,478.2 MMcf sold during 2002.
Weighted average oil sales prices of $21.00/Bbl during 2002 were 18% lower than $25.61/Bbl received in 2002 due to average marketplace
prices and the effects of a fixed price oil sales contract. Approximately 28% of Spinnaker’s total net oil sales volumes were sold under fixed prices of $27.53/Bbl during 2001. Eliminating the effect of this contract results in a weighted
average oil sales price of $24.86/Bbl during 2001. This contract was still in effect as of September 30, 2001. Weighted average natural gas prices of $2.52/Mcf were 49% lower in 2002 than $4.99/Mcf received in 2001 due to changes in marketplace
prices and the receipt of suspended funds attributable to several years of production from certain properties. Eliminating the effect of the receipt of these suspended funds results in weighted average natural gas sales prices of $2.78/Mcf.
Lease bonus and delay rental income of $15,000 was 56% lower in 2002 than $34,000 received in 2001 due to reduced
leasing activity. Other income of $190,000 was 443% higher in 2002 than $35,000 received in 2001 due primarily to non-recurring amounts received in 2002 attributable to litigation settlement proceeds.
Oil and natural gas production taxes of $467,000 in 2002 were 33% lower than $699,000 paid in 2001 due primarily to lower production
revenue.
Management expense of $235,000 during 2002 was 41% higher than $167,000 paid in 2001 due primarily to
increased rent and to salaries and benefits of employees of the general partner and its affiliates. Management expense reflects general and administrative costs that are reimbursed to the general partner in accordance with Spinnaker’s
partnership agreement.
Depletion expense of $1,278,000 in 2002 was 17% higher than $1,094,000 recorded in 2001
due to higher production volumes.
Other operating costs of $551,000 in 2002 were 138% higher than $232,000 paid
in 2001 due to increased legal and professional expenses and to expenses attributable to the proposed combination with Dorchester Hugoton and Republic.
10
Table of Contents
As a result, total expenses of $2,531,000 during 2002 were 15% higher than
$2,192,000 recorded in 2001, and net income of $3,565,000 during 2002 was 49% lower than $7,030,000 recorded in 2001 due primarily to lower oil and natural gas sales prices.
Liquidity and Capital Resources
Spinnaker’s only cash requirements are the limited partner distributions pursuant to its partnership agreement and the payment of (a) oil and gas production and property taxes not otherwise deducted from gross production
revenues, (b) operating expenses associated with the minor working interest properties not otherwise deducted from gross production revenues and (c) general and administrative expenses incurred in its behalf and properly allocated in accordance with
its partnership agreement. These cash requirements are funded with oil and natural gas production revenues, lease bonus and delay rental income and nonrecurring income generated from other sources. Since the limited partner distributions are, by
definition, determined after the payment of all expenses actually paid by the partnership, these payments do not represent obligations for which sufficient liquidity is at all times available. As a result, the only cash requirements that may create
liquidity concerns for Spinnaker are the payments of taxes and expenses as detailed above. These expenses ranged between 8.4% and 13.2% of total revenues during 1999, 2000 and 2001. Since most of these expenses are dependent upon oil and natural gas
prices and sales volumes, sufficient funds are anticipated to be available at all times for payment thereof.
Spinnaker is not liable for the payment of any exploration, development or production costs, with certain limited exceptions, which are both individually and in the aggregate insignificant. Spinnaker does not have any transactions,
arrangements or other relationships that could materially affect the partnership’s liquidity or the availability of capital resources. Spinnaker had no obligations and commitments to make future contractual payments as of September 30, 2002,
other than the September distribution payable to the Spinnaker partners in October 2002, as reflected in the financial statements. Spinnaker has not guaranteed the debt of any other party, nor does it have any other arrangements or relationships
with other entities that could potentially result in unconsolidated debt.
ADDITIONAL INFORMATION
See “Where You Can Find More Information” beginning on the inside front cover page of the proxy statement/prospectus
for more information on documents incorporated by reference and how to obtain them.
YOU ARE URGED TO READ THE
PROXY STATEMENT/PROSPECTUS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION BECAUSE IT CONTAINS IMPORTANT INFORMATION ABOUT THE COMBINATION, INCLUDING INFORMATION ABOUT (1) THE MANNER IN WHICH THE TERMS OF THE COMBINATION WERE DETERMINED AND (2)
CONFLICTING INTERESTS OF THE GENERAL PARTNERS OF THE COMBINING PARTNERSHIPS IN RECOMMENDING THE COMBINATION. COPIES OF THE PROXY STATEMENT/PROSPECTUS AND OTHER RELEVANT DOCUMENTS MAY BE OBTAINED WITHOUT CHARGE UPON REQUEST FROM DORCHESTER MINERALS
C/O DORCHESTER MINERALS MANAGEMENT GP LLC, 3738 OAK LAWN, SUITE 300, DALLAS, TEXAS 75219. YOU MAY ALSO OBTAIN THE PROXY STATEMENT/PROSPECTUS AND OTHER RELEVANT DOCUMENTS RELATING TO THE COMBINATION FREE THROUGH THE INTERNET WEB SITE THAT THE SEC
MAINTAINS AT WWW.SEC.GOV.
11
Table of Contents
APPENDIX
TO SUPPLEMENT NO. 1
| Dorchester Hugoton, Ltd. |
||
| F-1 | ||
| F-2 | ||
| F-2 | ||
| F-3 | ||
| F-4 | ||
| F-5 | ||
| Republic Royalty Company and Affiliated Partnership |
||
| F-7 | ||
| F-8 | ||
| F-9 | ||
| F-10 | ||
| F-11 | ||
| Republic Royalty Company — Unaffiliated Republic ORRIs Owners |
||
| F-15 | ||
| F-16 | ||
| F-17 | ||
| F-18 | ||
| F-19 | ||
| Spinnaker Royalty Company, L.P. |
||
| F-22 | ||
| F-23 | ||
| F-24 | ||
| F-25 | ||
| F-26 |
Table of Contents
BALANCE SHEET
(Dollars in Thousands)
(unaudited)
| September 30, 2002 | |||
| ASSETS |
|||
| Current assets: |
|||
| Cash and cash equivalents |
$ |
18,111 | |
| Investments available for sale |
|
4,083 | |
| Accounts receivable |
|
1,880 | |
| Prepaid expenses and other current assets |
|
341 | |
| |
| ||
| Total current assets |
|
24,415 | |
| |
| ||
| Property and equipment – at cost: |
|||
| Natural gas properties (full cost method) |
|
34,039 | |
| Other |
|
996 | |
| |
| ||
| Total |
|
35,035 | |
| Less accumulated depreciation, depletion and amortization: |
|||
| Full cost depletion |
|
20,120 | |
| Other |
|
361 | |
| |
| ||
| Total |
|
20,481 | |
| |
| ||
| Net property and equipment |
|
14,554 | |
| |
| ||
| Total assets |
$ |
38,969 | |
| |
| ||
| LIABILITIES AND PARTNERSHIP CAPITAL |
|||
| Current liabilities: |
|||
| Accounts payable |
$ |
599 | |
| Production and property taxes payable |
|
318 | |
| Royalties payable |
|
370 | |
| Distributions payable to Unitholders |
|
2,931 | |
| |
| ||
| Total liabilities |
|
4,218 | |
| |
| ||
| Commitments and contingencies (Notes 2 and 3) |
|||
| Partnership capital: |
|||
| General partners |
|
255 | |
| Unitholders |
|
32,930 | |
| Accumulated other comprehensive income |
|
1,566 | |
| |
| ||
| Total partnership capital |
|
34,751 | |
| |
| ||
| Total liabilities and partnership capital |
$ |
38,969 | |
| |
| ||
The financial information included herein
has been prepared by management without
audit by independent public accountants
See Notes to Financial Statements
F-1
Table of Contents
STATEMENTS OF EARNINGS
(Dollars in Thousands)
(unaudited)
| Nine Months Ended September 30, |
||||||||
| 2002 |
2001 |
|||||||
| Net operating revenues: |
||||||||
| Natural gas sales |
$ |
12,761 |
|
$ |
23,535 |
| ||
| Other |
|
96 |
|
|
152 |
| ||
| Production payment (ORRI) |
|
— |
|
|
(566 |
) | ||
| |
|
|
|
|
| |||
| Total net operating revenues |
|
12,857 |
|
|
23,121 |
| ||
| |
|
|
|
|
| |||
| Costs and expenses: |
||||||||
| Operating |
|
2,058 |
|
|
2,348 |
| ||
| Production taxes |
|
629 |
|
|
1,489 |
| ||
| Depreciation, depletion and amortization |
|
1,616 |
|
|
1,536 |
| ||
| General and administrative: |
||||||||
| Tax and regulatory reporting |
|
191 |
|
|
248 |
| ||
| Depositary and transfer agent fees |
|
18 |
|
|
17 |
| ||
| Other |
|
489 |
|
|
422 |
| ||
| Management fees |
|
381 |
|
|
484 |
| ||
| Merger costs and related expenses |
|
525 |
|
|
266 |
| ||
| Investment income |
|
(300 |
) |
|
(765 |
) | ||
| Interest expense |
|
14 |
|
|
28 |
| ||
| Other (income) expense, net |
|
21 |
|
|
(51 |
) | ||
| |
|
|
|
|
| |||
| Total costs and expenses |
|
5,642 |
|
|
6,022 |
| ||
| |
|
|
|
|
| |||
| Net earnings |
$ |
7,215 |
|
$ |
17,099 |
| ||
| |
|
|
|
|
| |||
| Net earnings per Unit |
$ |
0.66 |
|
$ |
$1.57 |
| ||
| |
|
|
|
|
| |||
(Dollars in Thousands)
(unaudited)
| Nine Months Ended September 30, |
||||||||
| 2002 |
2001 |
|||||||
| Net earnings |
$ |
7,215 |
|
$ |
17,099 |
| ||
| Unrealized holding gain (loss) on available for sale securities |
|
(947 |
) |
|
(521 |
) | ||
| |
|
|
|
|
| |||
| Comprehensive income |
$ |
6,268 |
|
$ |
16,578 |
| ||
| |
|
|
|
|
| |||
The financial information included herein
has been prepared by management without
audit by independent public accountants
See Notes to Financial Statements
F-2
Table of Contents
STATEMENTS OF CHANGES IN PARTNERSHIP CAPITAL
(Dollars in Thousands)
(unaudited)
| General Partners |
Unitholders |
Accumulated Other Comprehensive Income |
Total |
|||||||||||||
| Balance at December 31, 2001 |
$ |
271 |
|
$ |
34,552 |
|
$ |
2,513 |
|
$ |
37,336 |
| ||||
| Net earnings |
|
73 |
|
|
7,142 |
|
|
— |
|
|
7,215 |
| ||||
| Net unrealized holding gain on investments available for sale |
|
— |
|
|
— |
|
|
(947 |
) |
|
(947 |
) | ||||
| Distributions ($0.81 per Unit) |
|
(88 |
) |
|
(8,703 |
) |
|
— |
|
|
(8,791 |
) | ||||
| Other |
|
(1 |
) |
|
(61 |
) |
|
— |
|
|
(62 |
) | ||||
| |
|
|
|
|
|
|
|
|
|
|
| |||||
| Balance at September 30, 2002 |
$ |
255 |
|
$ |
32,930 |
|
$ |
1,566 |
|
$ |
34,751 |
| ||||
| |
|
|
|
|
|
|
|
|
|
|
| |||||
The financial information included herein
has been prepared by management without
audit by independent public accountants
See Notes to Financial Statements
F-3
Table of Contents
STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(unaudited)
| Nine Months Ended September 30, |
||||||||
| 2002 |
2001 |
|||||||
| Cash flows from operating activities: |
||||||||
| Net earnings |
$ |
7,215 |
|
$ |
17,099 |
| ||
| Adjustments to reconcile net earnings to net cash provided by operating activities: |
||||||||
| Depreciation, depletion and amortization |
|
1,616 |
|
|
1,536 |
| ||
| (Gain) loss on sale of property and equipment |
|
25 |
|
|
(11 |
) | ||
| Other |
|
(63 |
) |
|
(60 |
) | ||
| Changes in operating assets and liabilities: |
||||||||
| Restricted cash |
|
— |
|
|
(10 |
) | ||
| Accounts receivable |
|
(408 |
) |
|
2,513 |
| ||
| Prepaid expenses and other current assets |
|
112 |
|
|
(131 |
) | ||
| Accounts payable, taxes and royalties payable |
|
100 |
|
|
(1,654 |
) | ||
| |
|
|
|
|
| |||
| Net cash provided by operating activities |
|
8,597 |
|
|
19,280 |
| ||
| |
|
|
|
|
| |||
| Cash flows from investing activities: |
||||||||
| Capital expenditures |
|
(175 |
) |
|
(5,496 |
) | ||
| Cash received on sale of property and equipment |
|
41 |
|
|
26 |
| ||
| |
|
|
|
|
| |||
| Net cash used by investing activities |
|
(134 |
) |
|
(5,470 |
) | ||
| |
|
|
|
|
| |||
| Cash flows from financing activities: |
||||||||
| Distributions paid to Unitholders |
|
(8,791 |
) |
|
(9,876 |
) | ||
| |
|
|
|
|
| |||
| Increase (decrease) in cash and cash equivalents |
|
(328 |
) |
|
3,934 |
| ||
| Cash and cash equivalents at beginning of year |
|
18,439 |
|
|
15,767 |
| ||
| |
|
|
|
|
| |||
| Cash and cash equivalents at end of year |
$ |
18,111 |
|
$ |
19,701 |
| ||
| |
|
|
|
|
| |||
| Supplemental cash flow and other information: |
||||||||
| Interest paid (no interest was capitalized) |
$ |
22 |
|
$ |
20 |
| ||
| |
|
|
|
|
| |||
| Distributions declared but not paid |
$ |
2,931 |
|
$ |
2,932 |
| ||
| |
|
|
|
|
| |||
The financial information included herein
has been prepared by management without
audit by independent public accountants
See Notes to Financial Statements
F-4
Table of Contents
NOTES TO FINANCIAL STATEMENTS
Nine Months Ended September 30, 2002 and 2001 (unaudited)
1. General and Summary of Significant Accounting Policies
Nature of Operations—The Partnership’s operations consist principally of the operation of natural gas properties located
in Kansas and Oklahoma.
Basis of Presentation—The financial statements reflect all adjustments
(consisting only of normal and recurring adjustments) that are, in the opinion of management, necessary for a fair presentation of Dorchester Hugoton, Ltd.’s (the “Partnership’s”) financial position and operating results for the
interim period. Interim period results are not necessarily indicative of the results for the calendar year. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.
Per-Unit information is calculated by dividing the 99% interest owned by Unitholders by the 10,744,380 Units outstanding. Certain amounts in the 2001 financial statements have been reclassified to conform with the 2002 presentation.
Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in
the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents—The Partnership’s principal banking and short-term investing activities are with major financial institutions. Short-term investments with a maturity of three months or less are considered
to be cash equivalents and are carried at cost, which approximates fair value. Cash balances in these accounts may, at times, exceed federally insured limits. The Partnership has not experienced any losses in such cash accounts or investments and
does not believe it is exposed to any significant risk on cash and cash equivalents.
Concentration of Credit
Risks—The Partnership sells its natural gas to major corporate gas purchasers in the United States and either requires major corporate guarantees, good credit history with the Partnership, letters of credit, or performs on-going credit
evaluations or review of financial statements on a regular basis. The Partnership has incurred minimal credit losses.
Investments—The Partnership’s investments consist of 128,000 shares of Exxon Mobil Corporation (previously Exxon Corporation) common stock and are classified as available for sale. At September 30, 2002, the carrying
value of this stock, based on the quoted market price, was $4,083,200, and the cost was $2,517,455.
Property
and Equipment—The Partnership follows the full cost method of accounting prescribed by the United States Securities and Exchange Commission under which all costs relating to the acquisition, exploration and development of natural gas
properties (both productive and nonproductive) are capitalized (not to exceed estimated discounted future net cash flows) by the country (United States) in which the costs are incurred. Natural gas properties are being depleted on the
unit-of-production method using estimates of proved gas reserves. Other assets are being depreciated or amortized using straight-line methods for financial reporting purposes over estimated useful lives of 3 to 40 years.
Gains or losses are recognized upon the disposition of natural gas properties involving a significant portion of the Partnership’s
reserves. Proceeds from other dispositions of natural gas properties are credited to the full cost account.
Income Taxes—The Partnership is treated as a partnership for income tax purposes and, as a result, income or loss of the Partnership is includible in the tax returns of the individual Unitholders. Accordingly, no
recognition has been given to income taxes in the financial statements.
F-5
Table of Contents
DORCHESTER HUGOTON, LTD.
NOTES TO FINANCIAL STATEMENTS—(Continued)
2. Contingencies
In January 2002, some individuals and an association called Rural Residents for Natural Gas Rights, referred to as RRNGR, filed a lawsuit
against the Partnership, Anadarko Petroleum Corporation, Conoco, Inc., XTO Energy Inc., ExxonMobil Corporation, Phillips Petroleum Company, Incorporated and Texaco Exploration and Production, Inc. (“defendants”). The individuals and RRNGR
consist primarily of Texas County, Oklahoma residents who use natural gas at their own risk, free of cost from gas wells in residences located on leases. The plaintiffs seek declaration that their domestic gas use is not limited to stoves and inside
lights and is not limited to a principal dwelling as provided in the oil and gas lease agreements entered into in the 1930’s through the 1950’s. Plaintiffs also assert defendants conspired to restrain trade by warning of dangers of natural
gas use and using such warnings to induce some plaintiffs to release their domestic gas rights. Plaintiffs also seek certification of class action against defendants. Additionally, plaintiffs seek accounting of fuel use by defendants. Dorchester
Hugoton believes plaintiffs’ claims are completely without merit as to Dorchester Hugoton and has filed an answer. In July 2002 the defendants won a motion for summary judgment removing RRNGR as a plaintiff. Based upon past measurements of such
gas usage and current natural gas prices, Dorchester Hugoton believes the damages sought by plaintiffs to be minimal.
The Partnership is involved in several other legal and/or administrative proceedings arising in the ordinary course of its gas business, none of which have predictable outcomes and none of which are believed to have any significant
effect on the financial position or operating results of the Partnership.
3. Commitments
The Partnership adopted a severance policy during the first quarter of 1998. Benefits are generally payable to employees and
General Partner(s) in the event the Partnership incurs reduction in force or the elimination of a position or group of positions. The policy provides for up to approximately $2.8 million in severance payments if such obligations occur. Pursuant to
agreements related to the combination, such severance payments, estimated to be $2.7 million, will be paid by the Partnership prior to closing of the transaction.
4. Debt
Between 1994 and 2002 the
Partnership maintained an unsecured revolving credit facility for $15,000,000 with Bank One, Texas, N.A. While the latest borrowing base was $6,000,000, since August 1997 only $100,000 had been outstanding. On June 4, 2002 the Partnership repaid its
borrowings and terminated the agreement.
F-6
Table of Contents
AND AFFILIATED PARTNERSHIP
COMBINED BALANCE SHEET
September 30, 2002 (unaudited)
| Assets |
||||
| Current assets: |
||||
| Cash and cash equivalents |
$ |
999,554 |
| |
| Accounts receivable–ORRI |
|
3,159,552 |
| |
| |
|
| ||
| Total current assets |
|
4,159,106 |
| |
| |
|
| ||
| Oil and gas properties, at cost (full-cost method of accounting): |
||||
| Proved producing royalty interests |
|
4,299,814 |
| |
| Less accumulated depletion |
|
(3,002,154 |
) | |
| |
|
| ||
| Net oil and gas properties |
|
1,297,660 |
| |
| |
|
| ||
| Total assets |
$ |
5,456,766 |
| |
| |
|
| ||
| Liabilities and Owners’ Capital |
||||
| Current liabilities: |
||||
| Accounts payable |
$ |
1,009,008 |
| |
| Nonaffiliated ORRI Owner payable |
|
2,803,554 |
| |
| |
|
| ||
| Total current liabilities |
|
3,812,562 |
| |
| Owners’ capital |
|
1,644,204 |
| |
| |
|
| ||
| Contingencies (note 4) |
||||
| |
|
| ||
| Total liabilities and owners’ capital |
$ |
5,456,766 |
| |
| |
|
|
The financial information included herein
has been prepared by management without
audit by independent public accountants
See accompanying notes to combined financial statements
F-7
Table of Contents
AFFILIATED PARTNERSHIP
COMBINED STATEMENTS OF OPERATIONS
Nine months ended September 30, 2002 and 2001
(unaudited)
| September 30, 2002 (unaudited) |
September 30, 2001
(unaudited) | ||||
| Revenues: |
|||||
| Royalty income |
$ |
1,700,791 |
2,022,803 | ||
| Lease bonus income |
|
1,536 |
2,635 | ||
| Other income |
|
71,535 |
47,918 | ||
| |
|
| |||
| Total revenues |
|
1,773,862 |
2,073,356 | ||
| |
|
| |||
| Expenses: |
|||||
| Oil and gas production tax |
|
148,881 |
207,164 | ||
| Depletion expense |
|
127,247 |
74,101 | ||
| Other operating expenses |
|
364,191 |
156,148 | ||
| |
|
| |||
| Total expenses |
|
640,319 |
437,413 | ||
| |
|
| |||
| Net income |
$ |
1,133,543 |
1,635,943 | ||
| |
|
| |||
The financial information included
herein
has been prepared by management without
audit by independent
public accountants
See Notes to Financial Statements
F-8
Table of Contents
AND AFFILIATED PARTNERSHIP
COMBINED STATEMENTS OF OWNERS’ CAPITAL
Nine months ended September 30, 2002
(unaudited)
| Balance at December 31, 2001 |
$ |
1,822,077 |
| |
| Distributions to owners (unaudited) |
|
(1,311,416 |
) | |
| Net income (unaudited) |
|
1,133,543 |
| |
| |
|
| ||
| Balance at September 30, 2002 (unaudited) |
$ |
1,644,204 |
| |
| |
|
|
The financial information included herein
has been prepared by management without
audit by independent public accountants
See Notes to Financial Statements
F-9
Table of Contents
AND AFFILIATED PARTNERSHIP
COMBINED STATEMENTS OF CASH FLOWS
Nine months ended September 30, 2002 and 2001
(unaudited)
| September 30, 2002 (unaudited) |
September 30, 2001 (unaudited) |
||||||
| Cash flow from operating activities: |
|||||||
| Net income |
$ |
1,133,543 |
|
1,635,943 |
| ||
| Adjustments to reconcile net income to net cash provided by operating activities: |
|||||||
| Depletion expense |
|
127,247 |
|
74,101 |
| ||
| (Increase) decrease in accounts receivable |
|
(873,138 |
) |
1,728,075 |
| ||
| Increase (decrease) in accounts and royalty owners payable |
|
1,285,549 |
|
(2,357,525 |
) | ||
| |
|
|
|
| |||
| Net cash provided by operating activities |
|
1,673,201 |
|
1,080,594 |
| ||
| Cash flows from investing activities – facilitation amount |
|
58,915 |
|
401,038 |
| ||
| Cash flows from financing activities – distribution to owners |
|
(1,311,416 |
) |
(2,721,061 |
) | ||
| |
|
|
|
| |||
| Net increase (decrease) in cash and cash equivalents |
|
420,700 |
|
(1,239,429 |
) | ||
| Cash and cash equivalents at beginning of year |
|
578,854 |
|
1,906,903 |
| ||
| |
|
|
|
| |||
| Cash and cash equivalents at end of year |
$ |
999,554 |
|
667,474 |
| ||
| |
|
|
|
| |||
The financial information included herein
has been prepared by management without
audit by independent public accountants
See Notes to Financial Statements
F-10
Table of Contents
AND AFFILIATED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS
September 30, 2002 and 2001 (unaudited)
(1) Organization and Nature of Business
Republic Royalty Company (RRC or the Partnership) is a general partnership formed in September 1993 for the exclusive purpose of acquiring producing and nonproducing
mineral and royalty interests and working interests in five exploratory prospects (Properties) from multiple parties. SAM Partners, Ltd. (50% interest) (SAM) and Vaughn Petroleum, Inc. (50% interest) (VPI) are the sole partners of RRC.
Initial capitalization of RRC was comprised of certain contract and management rights of the partners and properties
contributed by VPI. Total cash consideration of $61.9 million was paid to the sellers of the Properties, which amount was funded with proceeds derived from the simultaneous sale of Overriding Royalty Interests (ORRI) to certain investors
(Nonaffiliated ORRI Owners) and to RRC NPI Holdings, L.P. (Affiliated Partnership or Affiliated ORRI Owner), a limited partnership. RRC is the general partner to the Affiliated Partnership, and various affiliates of SAM and VPI own 100% of the
Affiliated Partnership interests. In accordance with the applicable agreements governing these sales (ORRI Conveyance Agreements), RRC receives all revenues and pays all expenses attributable to the Properties and pays amounts to the owners of the
ORRI. The ORRI Conveyance Agreements state that the Nonaffiliated ORRI Owners (and/or their successors) and the Affiliated ORRI Owner are entitled to payment of amounts equal to 95.0% and 0.9%, respectively, of Net Proceeds as defined in the ORRI
Conveyance Agreements until the aggregate of all payments equals their investment (Payout No. 1), at which time their percentages are reduced to 85.5% and 0.81%. The percentages of Net Proceeds payable to the Affiliated ORRI Owner and the
Nonaffiliated ORRI Owners will reduce to 76.95% and 0.73%, respectively, when the aggregate of all payments equals a 14% annual return on their investment (Payout No. 2) as set forth in the ORRI Conveyance Agreements ($83,659,226 at December 31,
2001). Payout No. 1 was reached in August 2000. The percentages remained at 85.5% during 2002.
RRC recorded its
interest in the Properties at fair values based on the amounts paid by the Nonaffiliated ORRI Owners and the Affiliated Partnership for the ORRI.
(2) Basis of Presentation
(a) Basis of
Combination
The accompanying combined financial statements include the Partnership’s
share and the Affiliated Partnership’s share of revenues, expenses, and distributions for the nine months ended September 30, 2002 and 2001. The revenues, expenses, and amounts payable by and/or due to these parties varied during this time in
accordance with the ORRI Conveyance Agreements. Significant interaffiliate balances and transactions have been eliminated in combination. Revenues, expenses, and distributions attributable to the Nonaffiliated ORRI Owners are excluded from the
accompanying combined financial statements.
In the opinion of management, the unaudited financial
statements of the Partnership as of September 30, 2002 and for the nine months ended September 30, 2002 and 2001 include the adjustments and accruals which are necessary for a fair presentation of the results for the interim periods. These results
are not necessarily indicative of results for a full year.
(3) Summary of Significant Accounting Policies
A summary of the significant accounting policies followed by RRC and the Affiliated Partnership is as
follows:
(a) Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States
of America requires management to make estimates and assumptions that affect the
F-11
Table of Contents
REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the
reporting periods. Oil and gas reserve estimates are used in the calculation of depletion expense and the full-cost ceiling limitation for oil and gas properties and are inherently imprecise. Actual results could differ from those estimates.
(b) Capitalization Policy for Oil and Gas Activities
RRC and the Affiliated Partnership utilize the full-cost method of accounting for its oil and gas properties.
Under the full cost method, all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and gas reserves are capitalized and amortized on the units-of-production method based upon total
proved reserves of the underlying properties. Conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of oil and gas properties, with no gain or loss recognized.
Pursuant to the full cost method of accounting, the excess of the facilitation amount (management fees) over
actual general and administrative expenses incurred by the Partnership is credited to the full cost pool. During the nine months ended September 30, 2002 and 2001, the full cost pool was reduced by $58,915 and $401,038, respectively, for the excess
of the facilitation amount over actual general and administrative expenses incurred.
Under the
full cost method, the net book value of oil and gas properties may not exceed the estimated future net revenues from proved oil and gas properties, discounted at 10% per year (the ceiling limitation). In arriving at estimated future net revenues,
estimated lease operating expenses, development costs, abandonment costs, and certain production-related and ad valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held
constant indefinitely, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling limitation on an annual basis. The excess, if any, of the net book value above the ceiling limitation is
required to be written off as a noncash expense. There can be no assurance that there will not be writedowns in future periods under the full cost method of accounting as a result of sustained decreases in oil and gas prices or other factors.
(c) Depletion
RRC and the Affiliated ORRI Owner provide for depletion of proved producing oil and gas properties on a unit-of-production method, based upon studies by
independent engineers for proved oil and gas reserves.
(d) Cash Equivalents
RRC and the Affiliated Partnership consider all highly liquid investments purchased with
an original maturity of three months or less to be cash equivalents.
(e) Concentration of Credit Risk
Accounts
receivable balances represent revenue accruals from companies which operate primarily in the oil and gas industry. RRC and the Affiliated Partnership do not require collateral for their receivable balances. RRC and the Affiliated Partnership, as
well as the companies they do business with, are subject to fluctuations and trends in the oil and gas industry.
(f) Revenue Recognition
RRC and the
Affiliated Partnership use the sales method of accounting for oil and gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and gas sold to purchasers.
F-12
Table of Contents
REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
Revenue is recognized when earned and reasonably assured of collection. Royalty revenue in legal suspense is recorded when the legal dispute is settled.
(g) Income Taxes
RRC and the Affiliated Partnership are not subject to federal income taxes because the tax effect of their activities accrues to the partners and owners.
Taxable income or loss of RRC and the Affiliated Partnership is allocated to each partner and owner in accordance with the applicable Partnership and ORRI Conveyance Agreements, respectively. Accordingly, there is no provision for federal income
taxes reflected in the accompanying combined financial statements.
(h) Derivative
Instruments
Effective January 1, 2001, RRC and Affiliated Partnership adopted the
provisions of statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (Statement 133). Statement 133, as amended, standardizes the accounting for derivative instruments, including
certain derivative instruments embedded in other contracts. Under the standard, entities are required to report all derivative instruments in the statement of financial position at fair value. The accounting for changes in the fair value (i.e.,
gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, on the reason for holding the instrument. If certain conditions are met, entities may elect to
designate a derivative instrument as a hedge of exposures to changes in fair value, cash flows, or foreign currencies. RRC and Affiliated Partnerships held no fair value hedge or foreign currency hedge derivative instruments at September 30, 2002
and 2001.
(4) Litigation Settlements
RRC is or was a party to litigation concerning various contracts and other claims. At December 31, 2001, RRC and Affiliated Partnership were defendants in a proceeding
referred to as Salinas Litigation. The litigation involved claims of trespass to try title and adverse possession claim to a portion of a 180 acre tract of land, among other things, in which substantial mineral interests exist and with respect to
which all royalties from the tract have been deposited into an escrow account. In May 2002, RRC and Affiliated Partnership reached a settlement on the Salinas litigation whereby RRC and Affiliated Partnership were awarded record title to the mineral
interest, cash proceeds from royalty income previously held in legal suspense, and agreed to make certain payments to the plaintiffs. Included in the accompanying unaudited combined statement of operations for the nine months ended September 30,
2002 are royalty income, interest income, and legal and settlement costs, which are included in other operating costs, of $446,000, $37,000, and $181,000, respectively.
(5) Commitments and Contingencies
In the normal course of business, RRC and the Affiliated Partnership are involved in various lawsuits and claims related to their royalty properties. In the opinion of RRC’s management, the ultimate resolution of such matters
will not have a material adverse effect on the combined financial position or results of operations of RRC and Affiliated Partnership.
(6) Recent Accounting Pronouncements
In July 2001, the Financial
Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets. Statement 141
F-13
Table of Contents
REPUBLIC ROYALTY COMPANY
AND AFFILIATED PARTNERSHIP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
requires that all business combinations initiated after June 30, 2001 be accounted for under the purchase method, and Statement 142 requires that goodwill no longer be amortized to earnings, but
instead be reviewed for impairment. RRC and the Affiliated Partnership believe there is no impact of adopting this standard on their financial statements.
In June 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations, which establishes requirements for the accounting of removal-type costs associated with asset
retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. RRC and the Affiliated Partnership are currently assessing the impact on their financial statements.
In August 2001, the FASB issued Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which
establishes requirements for the accounting for the impairment or disposal of long-lived assets. The standard is effective for fiscal years beginning after December 15, 2001. RRC and Affiliated Partnership believe there will be no impact on their
financial statements from adopting this standard.
In April 2002, the FASB issued SFAS No. 145, Rescission of SFAS
Nos. 4, 44, and 64, Amendment of SFAS No. 13, and Technical Corrections. SFAS No. 145 eliminates SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, and thus allows for only those gains or losses on the extinguishment of debt
that meet the criteria of extraordinary items to be treated as such in the financial statements. SFAS No. 45 also amends SFAS No. 13, Accounting for Leases, to require sale-leaseback accounting for certain lease modifications that have
economic effects that are similar to sale-leaseback transactions. The provisions of this statement relating to the rescission of SFAS No. 4 are effective for fiscal years beginning after May 15, 2002. The provisions of this statement relating to the
amendment of SFAS No. 13 are effective for transactions occurring after May 15, 2002, and all provisions of this statement are effective for financial statements issued on or after May 15, 2002. Management believes the adoption of this statement
will have no material effect on its financial position or results of operations.
The Company will be required to
adopt SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities on January 1, 2003. SFAS 146 requires that costs associated with exit or disposal activities be recorded at their fair values when a liability has been
incurred. Under previous guidance, certain exit costs were accrued upon management’s commitment to an exit plan, which is generally before an actual liability has been incurred. Management is currently evaluating the impact of this Statement.
F-14
Table of Contents
INTERIM BALANCE SHEET
September 30, 2002 (unaudited)
| Assets |
||||
| Current assets: |
||||
| Accounts receivable—ORRI |
$ |
2,803,554 |
| |
| Oil and gas properties, at cost (full-cost method of accounting): |
||||
| Proved producing royalty interests |
|
64,961,084 |
| |
| Less accumulated depletion |
|
(38,010,284 |
) | |
| |
|
| ||
| Net oil and gas properties |
|
26,950,800 |
| |
| Total assets |
$ |
29,754,354 |
| |
| |
|
| ||
| Liabilities and ORRI Owners’ Equity |
||||
| Current liabilities—accounts payable |
$ |
862,702 |
| |
| ORRI owner’ equity |
|
28,891,652 |
| |
| Contingencies |
||||
| |
|
| ||
| Total liabilities and ORRI owner’ equity |
$ |
29,754,354 |
| |
| |
|
|
The financial information included herein
has been prepared by management without
audit by independent public accountants
See accompanying notes to combined financial statements
F-15
Table of Contents
STATEMENTS OF OPERATIONS
Nine months ended September 30, 2002 and 2001 (unaudited)
| September 30, 2002 (unaudited) |
September 30, 2001
(unaudited) | ||||
| Revenues: |
|||||
| Royalty income |
$ |
10,028,801 |
11,927,563 | ||
| Lease bonus income |
|
9,057 |
15,536 | ||
| Other income |
|
421,813 |
282,552 | ||
| |
|
| |||
| Total revenues |
|
10,459,671 |
12,225,651 | ||
| |
|
| |||
| Expenses: |
|||||
| Oil and gas production tax |
|
877,883 |
1,221,554 | ||
| Facilitation amount |
|
297,749 |
601,930 | ||
| Depletion |
|
2,642,764 |
2,319,090 | ||
| Other operating expenses |
|
2,091,666 |
468,136 | ||
| |
|
| |||
| Total expenses |
|
5,910,062 |
4,610,710 | ||
| |
|
| |||
| Net income |
$ |
4,549,609 |
7,614,941 | ||
| |
|
| |||
The financial information included herein
has been prepared by management without
audit by independent public accountants
See accompanying notes to combined financial statements
F-16
Table of Contents
STATEMENTS OF ORRI OWNERS’ EQUITY
Nine months ended September 30, 2002 (unaudited)
| Balance at December 31, 2001 |
$ |
31,614,479 |
| |
| Distributions to ORRI owners (unaudited) |
|
(7,272,436 |
) | |
| Net income (unaudited) |
|
4,549,609 |
| |
| |
|
| ||
| Balance at September 30, 2002 (unaudited) |
$ |
28,891,652 |
| |
| |
|
|
The financial information included herein
has been prepared by management without
audit by independent public accountants
See accompanying notes to combined financial statements
F-17
Table of Contents
STATEMENTS OF CASH FLOWS
Nine months ended September 30, 2002 and 2001 (unaudited)
| September 30, 2002 (unaudited) |
September 30, 2001
(unaudited) |
||||||
| Cash flow from operating activities: |
|||||||
| Net income |
$ |
4,549,609 |
|
7,614,941 |
| ||
| Adjustments to reconcile net income to net cash provided by operating activities: |
|||||||
| Depletion |
|
2,642,764 |
|
2,319,090 |
| ||
| (Increase) decrease in accounts receivable |
|
(549,370 |
) |
2,849,231 |
| ||
| Increase (decrease) in accounts payable and accrued expenses and other |
|
629,433 |
|
596,800 |
| ||
| |
|
|
|
| |||
| Net cash provided by operating activities |
|
7,272,436 |
|
13,380,062 |
| ||
| Cash flows from investing activities—distributions to ORRI owners |
|
(7,272,436 |
) |
(13,380,062 |
) | ||
| |
|
|
|
| |||
| Net increase in cash |
|
— |
|
— |
| ||
| Cash, beginning of period |
|
— |
|
— |
| ||
| |
|
|
|
| |||
| Cash, end of period |
$ |
— |
|
— |
| ||
| |
|
|
|
| |||
The financial information included herein
has been prepared by management without
audit by independent public accountants
See accompanying notes to combined financial statements
F-18
Table of Contents
NOTES TO FINANCIAL STATEMENT
September 30, 2002 and 2001 (unaudited)
(1) Organization and Nature of Business
Effective September 27,
1993, certain investors (Republic Unaffiliated ORRI Owners) represented by UBS Asset Management (New York) Inc. acquired a net profits interest (ORRI) in certain oil and gas minerals owned by Republic Royalty Company (RRC) pursuant to an ORRI
Conveyance Agreement (Agreement).
(2) Basis of Presentation
The accompanying financial statements include the Republic Unaffiliated ORRI Owners’ share of the acquired overriding royalty
interests and related revenues and expenses.
The Agreement provides for the establishment of a net proceeds
account for the purpose of providing a means of computing the amount of the net proceeds overriding royalty interest payments due to the Republic Unaffiliated ORRI Owners from RRC in connection with the Agreement. Generally, the net proceeds account
is increased for all cash generated from the subject minerals, as defined in the Agreement (gross proceeds) and decreased for direct operating costs and certain additional costs (production costs).
Cash is distributed as received by the Republic Unaffiliated ORRI Owners to its group members; accordingly, there is no cash balance
maintained.
(3) Summary of Significant Accounting Policies
A summary of the significant accounting policies followed by Republic Unaffiliated ORRI Owners are as follows:
(a) Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to
make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the
reporting periods. Oil and gas reserve estimates are used in the calculation of depletion expense and the full-cost ceiling limitation for oil and gas properties and are inherently imprecise. Actual results could differ from those estimates. In the
opinion of management, the unaudited financial statements of Republic Unaffiliated ORRI Owners as of September 30, 2002 and for the nine months ended September 30, 2002 and 2001 include the adjustments and accruals which are necessary for a fair
presentation of the results for the interim periods. These results are not necessarily indicative of results for a full year.
(b) Capitalization Policy for Oil and Gas Activities
Republic Unaffiliated ORRI Owners utilize the full cost method of accounting for its ORRI. Under the full cost method, all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development
of crude oil and natural gas reserves are capitalized and amortized on the units-of-production method based upon total proved reserves of the underlying properties. Conveyances of properties, including gains or losses on abandonments of properties,
are treated as adjustments to the cost of crude oil and natural gas properties, with no gain or loss recognized.
Under the full cost method, the net book value of the ORRI, may not exceed the estimated future net revenues from proved oil and natural gas properties, discounted at 10% per year (the ceiling limitation). In arriving at estimated
future net revenues, estimated lease operating expenses, development costs, abandonment
F-19
Table of Contents
REPUBLIC UNAFFILIATED ORRI OWNERS
NOTES TO FINANCIAL STATEMENTS—(Continued)
costs, and certain production related and ad-valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant
indefinitely, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling limitation on an annual basis. The excess, if any, of the net book value above the ceiling limitation is required
to be written off as a noncash expense. There can be no assurance that there will not be writedowns in future periods under the full cost method of accounting as a result of sustained decrease in oil and natural gas prices or other factors.
(c) Depletion
Republic Unaffiliated ORRI Owners provide for depletion of the proved producing royalty interest on a unit-of-production method, based upon studies by
independent engineers of the proved oil and gas reserves burdened by the net proceeds ORRI.
(d) Concentration of Credit Risk
Accounts
receivable balances represent revenue accruals from companies (flow through from RRC) which operate primarily in the oil and gas industry. Republic Unaffiliated ORRI Owners do not require collateral for its receivable balances. Republic Unaffiliated
ORRI Owners as well as the companies it does business with are subject to fluctuations and trends in the oil and gas industry.
(e) Revenue Recognition
Republic
Unaffiliated ORRI Owners use the sales method of accounting for oil and gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. Revenue is recognized when earned and reasonably assured
of collection. Royalty revenue in legal suspense is recorded when the legal dispute is settled.
(f) Income Taxes
Republic Unaffiliated ORRI
Owners are not subject to federal income taxes because the tax effect of its activities accrues to the individual owners. Taxable income or loss of Republic Unaffiliated ORRI Owners is allocated to each ORRI owner in accordance with their respective
ownership percentages. Accordingly, there is no provision for income taxes reflected in the accompanying financial statements.
(g) Derivative Instruments
Effective January
1, 2001, Republic Unaffiliated ORRI Owners adopted the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (Statement 133). Statement 133, as amended, standardizes
the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. Under the standard, entities are required to report all derivative instruments in the statement of financial position at fair value. The
accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as a part of a hedging relationship and, if so, on the reason for holding the instrument. If certain
conditions are met, entities may elect to designate a derivative instrument as a hedge of exposures to changes in fair value, cash flows, or foreign currencies. Republic Unaffiliated ORRI Owners held no fair value hedge or foreign currency hedge
derivative instruments at September 30, 2002 or 2001.
(4) Litigation Settlements
RRC is or was a party to litigation concerning various contracts and other claims. At December 31,2001, RRC and the Republic Unaffiliated
ORRI Owners were defendants in a proceeding referred to as Salinas
F-20
Table of Contents
REPUBLIC UNAFFILIATED ORRI OWNERS
NOTES TO FINANCIAL STATEMENTS—(Continued)
Litigation. The litigation involved claims of trespass to try title and adverse possession claim to a portion of a 180-acre tract of land, among other things, in which substantial mineral
interests exists and with respect to which all royalties from the tract were deposited into an escrow account. In May 2002, RRC and the Republic Unaffiliated ORRI Owners reached a settlement on the Salinas litigation whereby RRC and the Republic
Unaffiliated ORRI Owners were awarded record title to the mineral interest, cash proceeds from royalty income previously held in legal suspense, and agreed to make certain payments to the plaintiffs. Included in the accompanying unaudited combined
statement of operations for the nine months ended September 30, 2002 are royalty income, interest income, and legal and settlement costs, which are included in other operating costs, of $2,268,000, $217,000, and $1,065,000, respectively.
(5) Commitments and Contingencies
In the normal course of business, RRC is involved in various lawsuits and claims, related to its Royalty properties. In the opinion of RRC’s management, the ultimate
resolution of such matters will not have a material adverse effect on the financial position or results of operations of RRC or the ORRI interests.
(6) Recent Accounting Pronouncements
In July 2001, the Financial
Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets. Statement 141 requires that all business combinations initiated
after June 30, 2001 be accounted for under the purchase method, and Statement 142 requires that goodwill no longer be amortized to earnings, but instead be reviewed for impairment. Republic Unaffiliated ORRI Owners believe there is no current impact
on their financial statements.
In June 2001, the FASB issued Statement No. 143, Accounting for Asset
Retirement Obligations, which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged.
Republic Unaffiliated ORRI Owners are currently assessing the impact on their financial statements.
In August
2001, the FASB issued Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which establishes requirements for the accounting for the impairment or disposal of long-lived assets. The standard is effective for
fiscal years beginning after December 15, 2001. Republic Unaffiliated ORRI Owners believe there will be no impact on their financial statements from adopting this standard.
In April 2002, the FASB issued SFAS No. 145, Rescission of SFAS Nos. 4, 44, and 64, Amendment of SFAS No. 13, and Technical Corrections. SFAS No. 145 eliminates SFAS No. 4,
Reporting Gains and Losses from Extinguishment of Debt, and thus allows for only those gains or losses on the extinguishment of debt that meet the criteria of extraordinary items to be treated as such in the financial statements. SFAS No. 45
also amends SFAS No. 13, Accounting for Leases, to require sale-leaseback accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. The provisions of this statement relating to the
rescission of SFAS No. 4 are effective for fiscal years beginning after May 15, 2002. The provisions of this statement relating to the amendment of SFAS No. 13 are effective for transactions occurring after May 15, 2002, and all provisions of this
statement are effective for financial statements issued on or after May 15, 2002. Management believes the adoption of this statement will have no material effect on its financial position or results of operations.
The Company will be required to adopt SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities on January 1,
2003. SFAS No. 146 requires that costs associated with exit or disposal activities be recorded at their fair values when a liability has been incurred. Under previous guidance, certain exit costs were accrued upon management’s
commitment to an exit plan, which is generally before an actual liability has been incurred. Management is currently evaluating the impact of this Statement.
F-21
Table of Contents
INTERIM BALANCE SHEET
September 30, 2002 (unaudited)
| Assets |
||||
| Current assets: |
||||
| Cash and cash equivalents |
$ |
597,000 |
| |
| Accounts receivable |
|
1,184,000 |
| |
| |
|
| ||
| Total current assets |
|
1,781,000 |
| |
| |
|
| ||
| Oil and gas properties, at cost (full-cost method of accounting): |
||||
| Proved and producing royalty interests |
|
30,540,000 |
| |
| Unproved royalty interests |
|
— |
| |
| |
|
| ||
| |
30,540,000 |
| ||
| Less accumulated depletion |
|
(19,123,000 |
) | |
| |
|
| ||
| Net oil and gas properties |
|
11,417,000 |
| |
| |
|
| ||
| Total assets |
$ |
13,198,000 |
| |
| |
|
| ||
| Liabilities and Partners’ Capital |
||||
| Current liabilities—accounts payable and accrued expenses |
$ |
268,000 |
| |
| |
|
| ||
| Partners’ capital (deficit): |
||||
| General partner |
|
(346,000 |
) | |
| Limited partner |
|
13,276,000 |
| |
| |
|
| ||
| Total partners’ capital |
|
12,930,000 |
| |
| |
|
| ||
| Contingencies |
||||
| Total liabilities and partners’ capital |
$ |
13,198,000 |
| |
| |
|
|
The financial information included
herein
has been prepared by management without
audit by independent
public accountants
See accompanying notes to combined financial statements
F-22
Table of Contents
STATEMENTS OF OPERATIONS
Nine months ended September 30, 2002 and 2001 (unaudited)
| September 30, 2002 (unaudited) |
September 30, 2001
(unaudited) | ||||
| Revenues: |
|||||
| Royalty income |
$ |
5,891,000 |
9,153,000 | ||
| Lease bonus income |
|
15,000 |
34,000 | ||
| Interest and other income |
|
190,000 |
35,000 | ||
| |
|
| |||
| Total revenues |
|
6,096,000 |
9,222,000 | ||
| |
|
| |||
| Expenses: |
|||||
| Oil and gas production taxes and ad valorem taxes |
|
467,000 |
699,000 | ||
| Depletion |
|
1,278,000 |
1,094,000 | ||
| Management expense |
|
235,000 |
167,000 | ||
| Other operating expenses |
|
551,000 |
232,000 | ||
| |
|
| |||
| Total expenses |
|
2,531,000 |
2,192,000 | ||
| |
|
| |||
| Net income |
$ |
3,565,000 |
7,030,000 | ||
| |
|
| |||
The financial information included
herein
has been prepared by management without
audit by independent
public accountants
See accompanying notes to combined financial statements
F-23
Table of Contents
STATEMENTS OF PARTNERS’ CAPITAL
Nine months ended September 30, 2002 (unaudited)
| Limited partners |
General partner |
Total |
||||||||
| Balance at December 31, 2001 |
$ |
14,158,000 |
|
(303,000 |
) |
13,855,000 |
| |||
| Distribution to partners (unaudited) |
|
(4,270,000 |
) |
(220,000 |
) |
(4,490,000 |
) | |||
| Net income (unaudited) |
|
3,388,000 |
|
177,000 |
|
3,565,000 |
| |||
| |
|
|
|
|
|
| ||||
| Balance at September 30, 2002 (unaudited) |
$ |
13,276,000 |
|
(346,000 |
) |
12,930,000 |
| |||
| |
|
|
|
|
|
| ||||
The financial information included herein
has been prepared by management without
audit by independent public accountants
See accompanying notes to combined financial statements
F-24
Table of Contents
STATEMENTS OF CASH FLOWS
Nine months ended September 30, 2002 and 2001 (unaudited)
| September 30, 2002 (unaudited) |
September 30, 2001 (unaudited) |
||||||
| Cash flow from operating activities: |
|||||||
| Net income |
$ |
3,565,000 |
|
7,030,000 |
| ||
| Adjustments to reconcile net income to net cash provided by operating activities: |
|||||||
| Depletion expense |
|
1,278,000 |
|
1,094,000 |
| ||
| (Increase) decrease in accounts receivable |
|
(206,000 |
) |
967,000 |
| ||
| Increase (decrease) in accounts payable, accrued expenses, and other |
|
79,000 |
|
386,000 |
| ||
| |
|
|
|
| |||
| Net cash provided by operating activities |
|
4,716,000 |
|
9,477,000 |
| ||
| Cash flows from financing activities—distributions to partners |
|
(4,490,000 |
) |
(10,138,000 |
) | ||
| |
|
|
|
| |||
| Net increase (decrease) in cash and cash equivalents |
|
226,000 |
|
(661,000 |
) | ||
| Cash and cash equivalents at beginning of year |
|
371,000 |
|
1,049,000 |
| ||
| |
|
|
|
| |||
| Cash and cash equivalents at end of year |
$ |
597,000 |
|
388,000 |
| ||
| |
|
|
|
| |||
The financial information included
herein
has been prepared by management without
audit by independent
public accountants
See accompanying notes to combined financial statements
F-25
Table of Contents
NOTES TO FINANCIAL STATEMENTS
September 30, 2002 and 2001 (unaudited)
(1) Organization and Nature of Business
On September 4, 1997,
Spinnaker Royalty Company and others formed Spinnaker Royalty Company, L.P. (the Partnership) by contributing certain oil and gas mineral and royalty interests to the Partnership. Smith Allen Oil & Gas, Inc., is the Partnership’s general
partner. The primary business of the Partnership is to acquire, own, and manage oil and gas properties.
(2) Summary of Significant Accounting Policies
A summary of the
significant accounting policies followed by the Partnership is as follows:
(a) Capitalization Policy for Oil and Gas Activities
The Partnership utilizes the full cost method of accounting for its oil and gas properties. Under the full cost method, all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development
of oil and gas reserves are capitalized and amortized on the units-of-production method based upon total proved reserves. Conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of
oil and gas properties, with no gain or loss recognized.
Under the full cost method, the net book
value of oil and gas properties may not exceed the estimated future net revenues from proved oil and gas properties, discounted at 10% per year (the ceiling limitation). In arriving at estimated future net revenues, estimated lease operating
expenses, development costs, abandonment costs, and certain production-related and ad-valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except
for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling limitation on an annual basis. The excess, if any, of the net book value above the ceiling limitation is required to be written off as
a noncash expense. The Partnership did not incur ceiling limitation writedowns during 2001, 2000 and 1999. There can be no assurance that there will not be writedowns in future periods under the full cost method of accounting as a result of
sustained decreases in oil and gas prices or other factors.
(b) Depletion
The Partnership provides for depletion of proved and producing oil and gas properties on
a unit-of production method, based upon studies by independent engineers for proved oil and gas reserves.
(c) Cash Equivalents
The Partnership
considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
(d) Revenue Recognition
The Partnership uses
the sales method of accounting for oil and gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. Revenue is recognized when earned and reasonably assured of collection. Royalty
revenue in legal suspense is recorded when the legal dispute is settled.
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SPINNAKER ROYALTY COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS—(Continued)
(e) Concentration of Credit Risk
Accounts
receivable balances represent revenue accruals from companies which operate primarily in the oil and gas industry. The Partnership does not require collateral for its receivable balances. The Partnership as well as the companies it does business
with are subject to fluctuations and trends in the oil and gas industry.
(f) Income
Taxes
The Partnership is not subject to federal income taxes because the tax effect of
its activities accrues to the partners. Taxable income or loss of the Partnership is allocated to each partner in accordance with the Partnership agreement. Accordingly, there is no provision for income taxes reflected in the accompanying financial
statements.
(g) Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States
of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting periods. Oil and gas reserve estimates are used in the calculation of depletion expense and the full-cost ceiling limitation for oil and gas properties and are inherently imprecise. Actual results could
differ from those estimates. In the opinion of management, the unaudited financial statements of the Partnership as of September 30, 2002 and for the nine months ended September 30, 2002 and 2001 include the adjustments and accruals which are
necessary for a fair presentation of the results for the interim periods. These results are not necessarily indicative of results for a full year.
(h) Derivative Instruments
Effective January 1, 2001, the Partnership adopted the provisions of statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (Statement 133). Statement 133, as amended,
standardizes the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. Under the standard, entities are required to report all derivative instruments in the statement of financial position at
fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, on the reason for holding the
instrument. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposures to changes in fair value, cash flows, or foreign currencies. The Partnership held no fair value hedge or foreign currency
hedge derivative instruments at September 30, 2002 or 2001.
(3) Recent Accounting Pronouncements
In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting
Standards No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets. Statement 141 requires that all business combinations initiated after June 30, 2001 be accounted for under the purchase method, and Statement
142 requires that goodwill no longer be amortized to earnings, but instead be reviewed for impairment. The Partnership is not currently impacted by these statements.
In June 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations, which establishes requirement for the accounting of removal-type costs
associated with asset retirements. The standard
F-27
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SPINNAKER ROYALTY COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS—(Continued)
is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Partnership is currently assessing the impact of its financial statements.
In August 2001, the FASB issued Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which
establishes requirements for the accounting for the impairment or disposal of long-lived assets. The standard is effective for fiscal years beginning after December 15, 2001. The Partnership believes there will be no impact on their financial
statements from adopting this standard.
In April 2002, the FASB issued SFAS No. 145, Rescission of SFAS Nos. 4,
44, and 64, Amendment of SFAS No. 13, and Technical Corrections. SFAS No. 145 eliminates SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, and thus allows for only those gains or losses on the extinguishment of debt
that meet the criteria of extraordinary items to be treated as such in the financial statements. SFAS No. 45 also amends SFAS No. 13, Accounting for Leases, to require sale-leaseback accounting for certain lease modifications that have
economic effects that are similar to sale-leaseback transactions. The provisions of this statement relating to the rescission of SFAS No. 4 are effective for fiscal years beginning after May 15, 2002. The provisions of this statement relating to the
amendment of SFAS No. 13 are effective for transactions occurring after May 15, 2002, and all provisions of this statement are effective for financial statements issued on or after May 15, 2002. Management believes the adoption of this statement
will have no material effect on its financial position or results of operations.
The Company will be required to
adopt SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities on January 1, 2003. SFAS 146 requires that costs associated with exit or disposal activities be recorded at their fair values when a liability has been
incurred. Under previous guidance, certain exit costs were accrued upon management’s commitment to an exit plan, which is generally before an actual liability has been incurred. Management is currently evaluating the impact of this Statement.
(4) Commitments and Contingencies
In the normal course of business, the Partnership is involved in various lawsuits and claims related to its royalty properties. In the opinion of the Partnership’s management, the ultimate
resolution of such matters will not have a material adverse effect on the financial position or results of operations of the Partnership.
F-28