(2) Whenever the information needed to determine taxable quantities is not available when the tax return is due, the quantities reported must be based on the best information available on the reporting date. An adjustment must be shown on the next quarterly report correcting any errors in the estimate.

The following definitions apply to this subchapter:

(1) "Arm's-length transaction" means a contract, negotiation, or agreement between or among parties where the parties have independent interests and are not related.

(2) "Contract revenue" means the total receipts or accruals from all sales of coal during the reporting period.

(3) "FOB mine price" means contract revenue less reasonable and actual costs incurred to transport the taxable coal from the mine to a sales point remote from the mine after the coal is prepared for shipment.

(4) "Impute" means to assign a market value to coal by inference under circumstances set forth in 15-35-107, MCA.

(5) "Market value" means the value at which coal would change hands between a willing buyer and a willing seller under market and economic conditions at the time of sale, neither being under any compulsion to buy or to sell and both having reasonable knowledge of relevant facts. Agreements that are not arm's-length transactions will not be considered market value for purposes of filing the Montana coal production taxes.

(6) "Related parties" means any relationship that has the ability to influence whether each party has independent interests and could influence a party's independence in negotiating a transaction; or

(a) when any of the following circumstances exist:

(i) Affiliation. The parties are members, affiliates, subsidiaries, or any other affiliations under the same ownership of a parent entity.

(ii) Common control. The parties are, directly or indirectly, under common or joint control.

(iii) Family member. A party is a close family member of a person who is part of key management personnel or who controls another party to a transaction. A close family member is an individual's domestic partner and children, children of the domestic partner, and dependents of the individual or the individual's domestic partner.

(iv) Individual control. A party is controlled or significantly influenced by a member of key management personnel or by a person who controls another party to the transaction.

(v) Joint venture. The parties are members of a joint venture.

(vi) Key management. The parties share key management personnel.

(7) "Related-party transaction" is a contract, negotiation, or agreement between or among related parties, as defined in (6).

(a) Related-party transactions are not considered an arm's-length transaction as that term is defined in (1). 

(b) If at any time the parties to an arm's-length transaction become related parties, that agreement shall be considered to be a related-party transaction from that point forward.

(1) Each year on or before March 31, all persons engaged in mining coal in this state are required to compute and file the current Department of Revenue form reflecting the preceding calendar year production. All information requested on this form must be furnished and the form must be signed by an officer of the firm mining the coal.

(2) A person who sells coal under a contract which is not an arm's-length transaction must comply with (1) and must upon request of the department furnish a copy of their federal income tax return and copies of their current sales contracts.

(3) A person who is producing coal and who uses the production in their own manufacturing and/or energy conversion process must comply with (1) and (2).

(2) Any person refusing or neglecting to file after receipt of demand by the department will have the value of his coal computed by the department for gross proceeds tax purposes according to ARM 42.25.512.

(1) The contract sales price of the coal is calculated immediately after the point the coal is prepared for shipment to the first arm's-length purchaser of the coal. "Prepared for shipment" and "purchaser" are defined in 15-35-102, MCA. Contract sales price will be the calculated FOB mine price. Transportation costs that reduce the contract sales price of the coal shall not reduce the contract sales price below zero. The contract sales price will be further adjusted by deducting from either the FOB mine price or a value imputed by the department:

(a) the allowance for federal, state, and Indian royalties; and

(b) the amounts charged to the purchaser to pay taxes on production.

(2) The formula in (1) should be applied to each contract individually.

(1) When imputing value pursuant to 15-35-107, MCA, the department may use valuation methods which approximate the value of the coal, including but not limited to comparable actual arm's-length sales, comparable actual arm's-length sales adjusted to FOB mine price, or published coal sales indexes. Contract term, tonnage, quality, Btu rating, and any other appropriate comparability criteria will be considered.

(2) If using comparable sales in computing value, the department will maintain the confidentiality of all comparable contract data and will use contract data provided by the producer in question whenever possible.

(1) On or before July 1 each year the department will submit taxable valuations for each operating coal mine to the department's agent in the county where the coal was produced.

(1) The department may examine records of coal companies, including contracts for the sale of coal, to determine whether the price of coal as reported is the result of an agreement not at arm's length. The department will, if necessary, examine operator's records as they pertain to gross proceeds, make all adjustments required, and transmit the adjustments to the department's agent in the county and to the operator.

(2) The department also has the right to summon witnesses to appear and give evidence and to produce records, books, papers, and documents relating to any matter which the department shall have the authority to investigate and determine. Records obtained from the operator shall be considered confidential.

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(1) "After crushing" refers to after all crushing but before grinding.

(2) "Improvements and repairs" are defined as buildings and improvements to the land located at the mine site.

(3) "Mine" or "mining claim" is the location at which a mineral is produced, extracted, or quarried.   The mining claim may include one or more mines depending upon ownership (single) , location, integration of mining system, and single management.

(4) "Mineral" includes precious or semiprecious stones or gems, gold, silver, lead, coal, lime rock, granite, marble, travertine, talc, phosphate, and other minerals, rock, or stone extracted from underground mines, quarries, open pits, dumps, or tailings.

(5) "Reduction works" shall include mills, crushing, washing, or treatment plants that prepare the product mined to a point where it has marketable value.

(1) A return and statement for the assessment of net proceeds must be on the form prescribed by the department and must contain the following detailed information:

(a) name and address of the owner, lessee, or operator of the mining operation;

(b) name and address of the owner of the mine if other than that of the named operator;

(c) name and address of each royalty owner and the percentage of his royalty interest or the amount per ton, or other unit, which is to be paid under the royalty agreement and the actual amount paid to each royalty owner;

(d) county in which the mining operation is located, and if the mining operation extends across county lines, the percentage of the ore or mineral extracted from each county;

(e) legal description of the location of the mining operation by section, township and range, and the school district in which it is located, and if the mining operation extends into more than one school district, the percentage of ore of mineral extracted from each school district;

(f) the total tonnage must be reported (the value of the ore in components of monetary value for each mineral must be shown) :

EXAMPLE

Total tonnage mined                                                                 

                    oz. gold                         @$                              per oz.                   $               

                    oz. silver                        @$                              per oz.                   $               

                    lb. lead                          @$                              per lb.                    $                

                    lb. copper                     @$                              per lb.                    $                

                    tons                               @$                              per ton                   $                

                    carats                            @$                             per carat                $                

                                                                                          Total Value                                  

(g) deductions taken as listed and explained in ARM 42.25.1111 through 42.25.1117, and 42.25.1119;

(h) cost of transporting the product of the mining operation to the mill, smelter, or reduction works (depending on the specific operation) ;

(i) costs of operating the reduction works;

(j) costs of repairing and replacing the reduction works;

(k) assessed value of the reduction works as shown on the county tax rolls;

(l) costs of transporting the marketable product to the point of actual sale;

(m) costs of marketing the product and converting it into money;

(n) costs of construction, repairs, and improvements to the mine.

(2) No miscellaneous items will be allowed as deductions. All deductions must be itemized.

(3) Incomplete returns will not be accepted as satisfying the filing requirements.

(2) Each operator shall be notified of the assessment for each mine.  The taxpayer shall be notified of any changes made by the department when auditing the net proceeds return.

(1) The gross value of minerals subject to tax will be determined at the point where mining processes end and manufacturing or non-mining processes begin.   In general, mining includes overburden removal, blasting, loading, transportation between mining processes, sorting, reduction and drying.   Processes which will be considered non-mining are fine grinding, burning or calcining, blending with other materials, and treatment effecting a chemical change and packaging.

(a) The points at which mining processes end for specific minerals are listed below:

Mineral                                                                                                Valuation Point

Bentonite                                                                                    after crushing and drying

Gypsum                                                                                      after crushing

Limestone                                                                                  after crushing

Talc                                                                                             after crushing and sorting

Vermiculite                                                                                 after screening

(b) No deductions will be allowed for processing costs incurred beyond the valuation point.

(1) Gross value for purposes of the mines net proceeds will be determined at the point where mining processes end and manufacturing or non-mining processes begin as discussed in ARM 42.25.1104.

(2) Listed in the order in which they are to be considered, gross value at the point of valuation will be determined using one of the following methods:

(a) The producer's actual sales prices for mineral products sold at the point of valuation will be considered the best evidence of value provided the sales are arm's length and represent approximately 30% of total mineral production.   Sales of less than 30% of total production may be acceptable indicators of value if the sales price per unit is corroborated with other representative market data for minerals of like kind and grade.   Upon request, the producer must provide documentation for this method to the department.

 (b) If the producer does not have the sales information discussed in (2) (a) above, a market survey of other producers' sales of like kind and grade mineral products may be done.   If this method is used, the producer must obtain market data for three or more other producers.   This data must represent the results of competitive transactions in markets with a substantial number of unrelated buyers and sellers.   The producer must document that all values used are for minerals of comparable quality sold in quantities approximating the producer's level of production.   It may also be necessary to consider the geographic area served by the markets used for comparison.   Upon request, the producer must provide all information obtained that supports this method to the department.

(c) If the information required by (2) (a) and (b) above is not available, the proportionate profits method may be used to compute a value in the absence of adequate market data.   The general formula for this computation is:

                                    Direct costs through

                                    valuation point

Taxable value/unit =                       x Sales price/unit

                                   Total direct costs

(i) Direct costs through the valuation point will include overburden removal, drilling, blasting, loading, hauling, crushing, sorting, drying, mine reclamation, production taxes and royalties and any other direct costs incurred through the valuation point.

(ii) Total direct costs will include, in addition to those noted above, all direct costs applied to the mineral products up to the point of production of the first marketable product or group of products that have not been manufactured or fabricated. These costs will typically include grinding, burning or calcining, blending with other materials and treatment effecting a chemical change.

(iii) The sales price per unit will be the weighted average price of the first marketable product or group of substantially similar products sold in significant quantities by the producer.

(iv) Only direct costs may be used in computing the cost ratio for the formula.   No costs that benefit the operation as a whole or are not directly related to a specific phrase of the mining or processing of the mineral product will be included in the ratio.

(d) If warranted by an unusual situation, the department may use an alternative valuation method.

(1) All royalties (including those considered to be nontaxable) may be deducted in computing net proceeds as provided under ARM 42.25.1102 and 42.25.1103.

(2) Each royalty interest shall be assessed at its full cash value in the same manner as net proceeds regardless of the net proceeds of the operator or whether the operator deducted the royalty to arrive at the net proceeds.

(3) The department shall transmit royalty lists to the respective local department field office in the county where the mine is located.

(4) Each royalty owner shall be notified of the royalty assessment amount as reported by the mine operator.

(5) Certain royalties are considered nontaxable and shall not be assessed.   With certain exceptions as defined below, all royalties are subject to taxation.

(a) Royalties paid to the United States government, state of Montana, county, city, school district, or other political subdivision of the state are considered nontaxable.

(b) Royalties paid to Indian tribes from production on tribal land are taxable, but royalties paid to the United States government from production on allotted Indian land are nontaxable.

(2) Machinery shall include all that is used in:

(a) the construction;

(b) sinking, or running of shafts, tunnels, drifts; or

(c) other works in the extracting or mining of the ore deposit.

(3) In open pit and quarry mining operations, heavy equipment, including shovels, draglines, dozers, graders, loaders, trucks, railroad cars, locomotives, drilling, and pumping equipment used in the actual mining area (extracting ore to point of reduction) are to be considered as costs of machinery used in extracting and mining of the mineral.

(4) Expenditures for machinery or equipment rental used in the mining operations are deductible.

(5) No expenditures for machinery including leased and rented machinery shall be allowed as a deduction unless all machinery is reported to the local department field office in which the mine is located for assessment purposes.

(6) Deductions for mining equipment shared by otherwise separate mining operations must be pro-rated to each operation. Tonnage removed, man-hours expended, or other appropriate criteria may be used to allocate the expenses.

(7) Only the actual cost to acquire machinery and the subsequent direct operating, maintenance, and insurance costs are deductible.   Personal property taxes paid on machinery are not deductible.   Acquisition costs may include the cost of freight and delivery, assembly, installation, testing, and startup.

(1) Labor expenses will include amounts paid to employees, up to and including, mine and mill foremen and superintendents.   No deduction will be allowed for any person or officer not actually engaged in the mining or milling operations.   Labor expenses will be deductible to the extent they relate specifically to the mining and processing operations up to the point of mineral valuation for the following functions:

(a) overburden removal;

(b) drilling and blasting;

(c) loading;

(d) hauling;

(e) crushing;

(f) washing, sorting, and screening;

(g) drying;

(h) testing to satisfy federal and state health and safety laws;

(i) plant security;

(j) assaying and sampling;

(k) reclamation;

(l) engineering and geological services performed in Montana for existing operations; and

(m) equipment maintenance.

(2) Labor expenses are not deductible for the following functions:

(a) accounting and bookkeeping;

(b) legal;

(c) management above the superintendent level;

(d) engineering and geological services performed out of Montana or related to exploration;

(e) janitorial;

(f) laboratory work except as allowed in (h) and (j) above; and

(g) any other labor expenses incurred beyond the point of mineral valuation.

(3) The following items may be included in the amounts deducted for the functions listed in (1) :

(a) wages and salaries;

(b) overtime;

(c) holiday and vacation pay;

(d) shift differentials;

(e) payroll taxes;

(f) health and welfare benefits;

(g) safety clothing;

(h) locker and shower facilities;

(i) meal expenses;

(j) bonuses;

(k) safety training;

(l) transportation to the mine provided by employer;

(m) workers' compensation insurance; and

(n) retirement fund contributions provided for in labor contracts.

(4) Accounting records for labor expenses must be maintained by the taxpayer.  These records must include contemporaneous man-hour logs for employees who do not work 100% of their time in one of the functions listed in (1) or who are involved in processing minerals both up to and beyond the point of mineral valuation.

(1) All monies expended for costs of repairs and replacements of the milling and reduction works used in connection with the mine may be deducted in computing net proceeds as provided under ARM 42.25.1102 and 42.25.1103.  There must not be included in this schedule any amount expended for the construction of new buildings or the purchase or installing of new machinery or apparatus that are in the nature of additions or improvements to plant or equipment.  Deductions are allowable when the buildings constructed or repaired, or machinery purchased and installed, are for the sole purpose of replacing old, worn out, or obsolete buildings or machinery.

(2) If the person working the mine or deposit also operates the mill or reduction works and mills, or treats the ore or deposit, 6% of the assessed valuation for the calendar year the return represents may be deducted.   However, if the mill or reduction works is used to mill or treat the ore or deposit from any other mine or mines, then the amount of the 6% assessed valuation must be apportioned so that only the proper proportionate part thereof will be included in this return.

(3) Milling and reduction expenses are either:

(a) repairs or replacements; or

(b) additions or improvements to the plant.

(4) Costs for repairs and replacements which are fully deductible when incurred may not be added to the 6% assessed valuation base.

(2) Actual marketing costs directly related to the sale of mineral products processed up to the point of valuation for net proceeds purposes may be deducted.   These expenses may include the applicable salesperson's salary and/or commission, technical assistance, and advertising, but only to the extent these expenses pertain specifically to the mineral product processed up to the point of valuation.   Marketing expenses related to mineral products processed beyond that point may not be allocated back to mineral products that are not sold until further processing has occurred.   Technical and scientific testing costs will not be considered marketing, but may be deductible if they meet the requirements of 15-23-503(1) (h) , MCA.

(3) All expenses for fire insurance, boiler and machinery insurance, and public liability insurance paid for the mine, reduction works or beneficiation process are deductible.

(4) No payments for taxes on production, license taxes, corporation, income, sales, real estate, personal property, and excise taxes may be used as a deduction.

(5) No expenses for land lease rental or for land lease holdings may be used as a deduction.

(1) Mines Net Proceeds, Title 15, chapter 23, part 5, MCA, as amended, provides for the ad valorem taxation of minerals as they are extracted from the ground and is intended to provide a tax in lieu of a property tax on such minerals. To determine the assessed value of the mineral, certain specific expenses are permitted as deductions from the gross value of the mineral.

(2) The purpose of the regulations is to set forth the intent of the law and its interpretation by the courts and to provide firm, unambiguous guidelines for valuing the product of a mining operation. The method followed determines the actual value of the extracted mineral and allows the deduction of just and equitable costs incurred in the actual mining, reduction, and marketing of the product.

(3) The Mines Net Proceeds law provides for limited deductions incurred at the mine location in Montana and not the broad spectrum of deductions allowed by income tax laws. These deductions are specific and should not be construed to include items not listed. The deductions may vary depending on the point of valuation of the mineral, but will never be greater than those provided by statute.

(2) The cost of welfare and retirement fund payments provided for in wage contracts shall be deductible only for those employees actually involved in the mining or reduction work up to the point of valuation.

(3) The cost of testing minerals extracted, in satisfaction of federal or state health and safety laws or regulations, will be allowed for the mines and reduction works up through the beneficiation process to the extent that the costs are incurred for testing the product to the point of valuation.

(4) The cost of security, in and around the mine and including the cost of security around the mill or reduction works in Montana, shall be deductible provided these costs are not incurred beyond the point of valuation.

(5) The cost of assaying and sampling for extracted minerals will be allowed to the extent that they are a part of processes that bring the mineral to the point of valuation.

(6) Engineering and geological services will be allowed as described in 15-23-503, MCA.

(7) The cost of labor, supplies, and equipment used to reclaim the mine site are deductible.   If during the process of reclamation, other costs are incurred that result in an improvement in and about the working of the mine, those costs will be amortized over a ten-year period.   The deductions provided in this section are allowable beginning in the 1985 production year.

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The following definitions apply to this chapter:

(1) "Mineral" as used for resource indemnity trust tax purposes, means any precious stones or gems, gold, silver, copper, coal, lead, scoria, travertine, petroleum, natural gas, oil, uranium, or other nonrenewable merchantable products extracted from the surface or subsurface of the state of Montana, including sand and gravel.

(1) The resource indemnity trust tax is computed on the gross value of the mineral at the time of extraction from either the surface or subsurface of the earth. 

(2) Producers may not reduce gross value for any costs or expenses of bringing minerals to mine mouth.

(1) Preparation and filing of the resource indemnity trust tax statement of gross yield and payment of the tax due is the direct and sole responsibility of every individual, partnership, firm, association, joint stock company, syndicate, or corporation who engages in or carries on the business of mining, extracting, or producing a mineral, as defined in Title 15, chapter 38, MCA.

(2) This responsibility may not be delegated or transferred to the owner of the property from which minerals are extracted or produced, if different from the producer, or to the purchaser of the minerals.

(3) A producer who has filed a metal mines license tax return pursuant to Title 15, chapter 37, part 1, MCA, does not also need to file a resource indemnity trust return.   Not filing a resource indemnity trust return does not relieve the producer from the obligation to pay the tax.   A producer of gold, silver, copper, lead, or any other metal or metals or precious or semiprecious gems or stones who does not file a metal mines license return must file a resource indemnity trust tax return.

(1) Attachments may be made to the resource indemnity trust tax statement of gross yield if space is not adequate on the form to provide complete information.   Companies using data processing equipment may provide computer printouts to supply the production information if columns and/or totals are properly identified.

(1) The minimum annual tax of $25 is due only once each year from each individual, partnership, firm, association, joint-stock company, syndicate, or corporation who engages in or carries on the business of mining, extracting, or producing a mineral. Likewise the $5,000 reduction of gross value of product may be claimed only once each year by a producer.

(1) For all minerals except oil and gas, gross value of product for purposes of the resource indemnity trust tax will be determined at the time of extraction from the ground. The time of extraction is after loading the raw mineral product and before any hauling or transportation occurs.

(2) Gross value of product at the time of extraction will be determined using one of the following methods for each product produced as noted:

(a) For coal, the gross value of the product is the "contract sales price" for the coal severance as stated in 15-35-102, MCA, times the tons produced; except the tonnage exemption defined in 15-35-103, MCA, cannot be claimed in computing the resource indemnity trust tax.

(i) If the department imputes a value for coal pursuant to 15-35-107, MCA, the same imputed value will be used in computing the resource indemnity trust tax.

(b) For talc, the gross value of the product is the tons produced in the year for which a return is filed times the value stated in 15-23-515, MCA.

(c) For vermiculite, the gross value of the product is the tons produced in the year for which a return is filed times the value stated in 15-23-516, MCA.

(d) For gold, silver, copper, lead, or any other metal or metals, or precious, semiprecious gems or stones, of any kind for which a resource indemnity trust tax return is filed, the gross value of the product is the "receipts received" as defined in 15-23-801, MCA.

(e) For lime rock, granite, marble, travertine, phosphate, bentonite, barite and other minerals, rock or stone extracted from underground mines, quarries, or open pits, gross value at the time of extraction will be determined using one of the following methods which are listed in the order they are to be considered:

(i) The producer's actual sales prices for mineral products sold at the time of extraction will be considered the best evidence of value provided the sales are arm's length and represent more than 30 percent of total mineral production. Sales of less than 30 percent of total production may be acceptable indicators of value if the sales price per unit is corroborated with other representative market data for minerals of like kind and grade. Upon request, the producer must provide documentation for this method to the department.

(ii) If the producer does not have the sales information discussed in (2)(e)(i) above, a market survey of other producers' sales of like kind and grade mineral products may be done. If this method is used, the producer must obtain market data for three or more other producers. This data must represent the results of competitive transactions in markets with a substantial number of unrelated buyers and sellers. The producer must document that all values used are for minerals of comparable quality sold in quantities approximating the producers level of production. It may also be necessary to consider the geographic area served by the markets used for comparison. All information obtained by the producer to support this method must be provided to the department on request.

(iii) If the information required by (2)(e)(i) or (ii) above is not available, the proportionate profits method may be used to compute a value in the absence of adequate market data. The general formula for this computation is stated below.

                                                Direct costs through

                                                extraction

Taxable value/unit = ____________________ x Sales price/unit

                                                Total direct costs

(A) Direct costs through extraction will include overburden removal, drilling, blasting, loading, mine reclamation, royalties and any other direct costs incurred through the loading process.

(B) Total direct costs will include, in addition to those noted above, all direct costs applied to the mineral products up to the point of production of the first marketable product or group of products that have not been manufactured or fabricated. These costs will typically include hauling, sorting, crushing, grinding, drying, smelting, refining, etc. Final reclamation costs related to dismantling facilities may also be included in total direct costs.

(C) The sales price per unit will be the weighted average price of the first marketable product or group of substantially similar products sold in significant quantities by the producer. The first marketable product or group of products will not include manufactured products. For example, a cement producer must use the sales price of bulk cement not the price of concrete blocks he may manufacture from the cement.

(D) Only direct costs may be used in computing the cost ratio for the formula. No costs that benefit the operation as a whole or are not directly related to a specific phase of the mining or processing of the mineral product will be included in the ratio.

(iv) The department may use an alternative valuation method if warranted by an unusual situation.

(3) For oil and gas, gross value of product for the purposes of the resource indemnity trust tax will be determined at the time of extraction at the wellhead. The gross value of product is the total value of all petroleum and other mineral or crude oil or natural gas produced each year. The value is determined by taking the total number of barrels or cubic feet produced each month during such year at the average value at the mouth of the well during the month the product is produced. However, the total value shall be reduced for royalties paid to the United States, the state of Montana, Indians, Indian tribes, a county, or municipal government.

(1) Deductions from total kilowatt hours generated will be allowed only for actual and necessary plant use. No deduction is allowed for any line losses.

The following definitions apply to this subchapter:

(1) "Arm's-length transaction" means a contract, negotiation, or agreement between or among parties where the parties have independent interests and are not related.

(2) "Contract revenue" means the total receipts or accruals from all sales of coal during the reporting period.

(3) "FOB mine price" means contract revenue less reasonable actual costs incurred to transport the taxable coal from the mine to a sales point remote from the mine after the coal is prepared for shipment.

(4) "Impute" means to assign a market value to coal by inference under circumstances set forth in 15-35-107, MCA.

(5) "Market value" means the value at which coal would change hands between a willing buyer and a willing seller under market and economic conditions at the time of sale, neither being under any compulsion to buy or to sell and both having reasonable knowledge of relevant facts. Agreements that are not arm's-length transactions will not be considered market value for purposes of filing the Montana coal production taxes.

(6) "Related parties" means any relationship that has the ability to influence whether each party has independent interests and could influence a party's independence in negotiating a transaction; or

(a) when any of the following circumstances exist:

(i) Affiliation. The parties are members, affiliates, subsidiaries, or any other affiliations under the same ownership of a parent entity.

(ii) Common control. The parties are, directly or indirectly, under common or joint control.

(iii) Family member. A party is a close family member of a person who is part of key management personnel or who controls another party to a transaction. A close family member is an individual's domestic partner and children, children of the domestic partner, and dependents of the individual or the individual's domestic partner.

(iv) Individual control. A party is controlled or significantly influenced by a member of key management personnel or by a person who controls another party to the transaction.

(v) Joint venture. The parties are members of a joint venture.

(vi) Key management. The parties share key management personnel.

(7) "Related-party transaction" is a contract, negotiation, or agreement between or among related parties, as defined in (6).

(a) Related-party transactions are not considered an arm's-length transaction as that term is defined in (1).

(b) If at any time the parties to an arm's-length transaction become related parties, that agreement shall be considered to be a related-party transaction from that point forward.

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This rule has been repealed.

(1) The contract sales price of the coal is calculated immediately after the point the coal is prepared for shipment to the first arm's-length purchaser of the coal. "Prepared for shipment" and "purchaser" are defined in 15-35-102, MCA. Contract sales price will be the calculated FOB mine price. Transportations costs that reduce the contract sales price of the coal shall not reduce the contract sales price below zero. The contract sales price will be further adjusted by deducting from either the FOB mine price or a value imputed by the department:

(a) the allowance for federal, state, and Indian royalties; and

(b) the amounts charged to the purchaser to pay taxes on production.

(2) The formula in (1) should be applied to each contract individually.

(1) When imputing value pursuant to 15-35-107, MCA, the department may use valuation methods which approximate the value of coal, including but not limited to comparable actual arm's-length sales, comparable actual arm's-length sales adjusted for FOB mine price, or published coal sales indexes. Contract term, tonnage, quality, Btu rating, and any of the appropriate comparability criteria will be considered.

(2) If using comparable sales in computing value, the department will maintain the confidentiality of all comparable contract data and will use contract data provided by the producer in question whenever possible.

(1) The department may examine records of coal companies and their related parties, including contracts for the sale of coal, to determine the price of coal. Records obtained shall be considered confidential.

In addition to the definitions found in 15-36-303, MCA, the following definitions apply to terms used in this subchapter:

(1) "Arm's-length contract" means a contract or an agreement to sell that has been arrived at between independent, nonaffiliated parties with adverse economic interests. Contracts or agreements for the purposes of these rules will be defined to be non-arm's-length if the parties to the contract or agreements have business relationships other than the agreement between the buyer and seller which have influenced the sales price.

(2) "Central facilities" are installations which are used to cool, heat, separate, dehydrate, compress, sweeten, or gather/transport natural gas at a point remote from the well or wells.

(3) "Delivery point" means a point away from the well or lease where the natural gas is sold.

(4) "Delivery price adjustments" includes all expenses directly incurred and paid for in the operation and maintenance of "central facilities". Delivery price adjustments are merely a reduction in price and are not meant to be a deductible expense beyond the well or wells. Delivery price adjustments only occur when the department deems it necessary to establish the correct natural gas gross value.

(5) "Lease" means that particularly described tract of land contained in a contract in writing whereby a person having a legal interest in the land so described conveys a portion of his interest to another, in consideration of a certain rental or other recompense or consideration. A lease may contain one or more wells. One operator shall be named as the lease operator and shall be responsible for filing the oil and natural gas production tax return.

(6) "MCF" means 1,000 cubic feet of natural gas measured at a pressure of 14.73 pounds per square inch and a temperature of 60 degrees Fahrenheit.

(7) "Natural gas" means a mixture of hydrocarbon gases and other products which at normal atmospheric conditions of temperature and pressure are in a gaseous state. This includes coalbed methane gas.

(8) "Natural gas liquids" means all ethane, butane, propane, hexane, heptane, and heavier gases which are removed for natural gas by processing.

(9) "Producing well" means a well that produced natural gas, petroleum, or other crude or mineral oil in the year prior to the current calendar year.

(a) A well that is used for injection purposes only is not a producing well.

(b) A well that produces only water is not a producing well.

(c) A well that was capable of producing oil or gas but in fact did not produce oil or gas in the year prior to the current calendar year is not a producing well.

(10) "Qualifying production time period" is the first 12 months of production of a vertical well or the first 18 months of production of a horizontally completed well.

(11) "Stripper well bonus" applies to wells producing an average of three barrels a day or less, and the average price received by a producer for their Montana production for a barrel of crude oil during a calendar quarter is equal to, or greater than, $54 a barrel. The average daily production is calculated by dividing the amount of production from a lease or unitized area for the year immediately preceding the current calendar year, by the number of producing wells in the lease or unitized area, and by dividing the resulting quotient by 365. The average price for a barrel is computed by dividing the sum of the total revenue received for all crude oil sold from wells within the state of Montana for the calendar quarter by the number of barrels sold in the quarter.

(12) "Stripper well exemption" applies to wells producing an average of three barrels a day or less, and the average price received by a producer for their Montana production for a barrel of crude oil during a calendar quarter is less than $54 a barrel. The average daily production is calculated by dividing the amount of production from a lease or unitized area for the year immediately preceding the current calendar year by the number of producing wells in the lease or unitized area and by dividing the resulting quotient by 365. The average price for a barrel is computed by dividing the sum of the total revenue received for all crude oil sold from wells within the state of Montana for the calendar quarter by the number of barrels sold in the quarter.

(13) "Unit operation" is one in which persons owning leasehold interest in one or more pools or portions thereof in a field combine their operations to function as one unit operation for pressure maintenance of secondary recovery purposes, to increase ultimate recovery, or to prevent waste of gas from pools or portions of pools where gas only is produced. One operator must be named as the unit operator and shall be responsible for filing the oil and natural gas production tax return.

(a) In addition to the contents of the petition outlined in ARM 42.2.103, a petition must delineate the well or wells for which the petition is submitted.

(2) The fact that a person did not petition the department for a declaratory ruling regarding the applicability of a statute and regulation, or both of them, to that person's activity or proposed activity shall not be construed as a failure to exhaust administrative remedies in any subsequent administrative or judicial review, or litigation, between the department and the person involved over any particular item with respect to the oil and natural gas production tax.

(2) Nonworking interest owners' oil and natural gas production is subject to different tax rates than the working interest, as shown in ARM 42.25.1809.

(1) For horizontally completed or horizontally recompleted wells the operator must provide to the department of revenue a copy of the horizontal certification from the board of oil and gas conservation. If the operator does not provide the certification, or the well is not certified by the board as horizontally completed, production from the well will be subject to the tax rates in ARM 42.25.1809(1) (b) (i) for oil wells, and 42.25.1809(1) (a) (i) for gas wells until such time as operator provides the certification to the department. If a certification is received by the department after the month in which production for sale first occurs, and the taxpayer has filed and paid taxes on production which is greater than would otherwise be due, a refund or credit will be granted to the taxpayer.

(2) Production from pre-1999 and post-1999 wells certified by the board to be horizontally completed will be subject to the tax rates in ARM 42.25.1809(1) (b) (iii) (A) for oil wells, and 42.25.1809(1) (a) (iii) (A) for post-1999 gas wells for the first 18 months following the last day of the calendar month immediately preceding the month in which production for sale from a crude oil or natural gas well is pumped or flows. Production from pre-1999 certified horizontal wells will be subject to the tax rates under ARM 42.25.1809(1) (b) (iii) (B) after the first 18 months of production unless it is a stripper producer or has incremental production. Production from post-1999 certified horizontal oil wells will be subject to the tax rates under ARM 42.25.1809(1) (b) (iii) (C) after the first 18 months of production unless it is a stripper producer or has incremental production. Production from post-1999 certified horizontal gas wells will be subject to the tax rates under ARM 42.25.1809(1) (a) (iii) (B) after the first 18 months of production.

Example : The first production for sale from a horizontally drilled oil well is February 18, 1998.

February 1998 is considered the first month of production subject to the tax rates in ARM

42.25.1809(1) (b) (iii) (A) , and the last month of the exemption will be July 1999. The first

month of production subject to the tax rates in ARM 42.25.1809(1) (b) (iii) (B) in this example

is August 1999. The tax rates in ARM 42.25.1809(1) (b) (iii) (A) will apply to the month in which

production for sale first occurs regardless of when the operator provides a copy of the

certification notice to the department.

(3) All production from wells certified by the board to be horizontally recompleted which have produced oil during the five years immediately preceding the month the well was horizontally recompleted will be classified as incremental and the tax rates in ARM 42.25.1809(1) (b) (v) apply.

(4) This section applies to a well reported as a pre-1999 oil well prior to recompletion as a horizontal well. For oil wells certified by the board to be horizontally recompleted, the tax rates in ARM 42.25.1809(1) (b) (v) (A) and (B) apply to the incremental production. The operator must provide a production decline rate approved by the board. If a well is in primary recovery after the first 18 months of production the well will be classified as a pre-1999 well, and the tax rates in ARM 42.25.1809(1) (b) (i) (B) will apply, or if qualified as a stripper well the rates in ARM 42.25.1809(1) (b) (ii) (A) and (B) , or 42.25.1809(1) (b) (ii) (C) apply.

(5) This section applies to a well reported as a post-1999 oil well prior to recompletion as a horizontal well. For oil wells certified by the board to be horizontally recompleted, the tax rates in ARM 42.25.1809(1) (b) (v) (A) and (C) apply to the incremental production. The operator must provide a production decline rate approved by the board. If a well is in primary recovery after the first 18 months of production the well will be classified as a post-1999 well, and the tax rates in ARM 42.25.1809(1) (b) (i) (C) will apply, or if qualified as a stripper well the rates in ARM 42.25.1809(1) (b) (ii) (A) and (B) or 42.25.1809(1) (b) (ii) (C) apply.

(2) A tax return shall be filed for the wells in each designated area. If the designated area for a new or expanded enhanced recovery project does not include all the wells reported as a lease or unit for tax purposes prior to the inception of the new or expanded enhanced recovery project, the wells not included in the designated area approved by the board will continue to be reported as a lease or unit for tax purposes and none of the production from wells outside the designated area can be reported as incremental.

(3) No production will qualify as incremental prior to January 1, 1994. For new or expanded projects commenced after January 1, 1994, approval should be obtained from the board for the project prior to the due date of any production tax returns. If, however, such approval is not received until after the returns are filed for any quarter the operator may file amended returns after the board has approved the project and established a production decline rate for the project.

(2) The amount of tax to be paid at pre-1999 and post-1999 tax rates will be based upon a production ratio determined each calendar year.

(a) The pre-1999 ratio will be computed by dividing incremental and non-incremental production for the previous calendar year from wells classified as pre-1999 wells by the total production for the previous calendar year from the designated area of the new or expanded recovery project.

(b) The post-1999 ratio will be computed by dividing incremental and non-incremental production for the previous calendar year from wells classified as post-1999 wells by the total production for the previous calendar year from the designated area of the new or expanded recovery project.

(3) Incremental production to be reported as pre-1999 wells is the amount of production computed when the pre-1999 ratio determined above is multiplied times the total incremental production for the quarter. The amount of non-incremental pre-1999 production to be reported is determined by subtracting the amount of pre-1999 incremental production from the total pre-1999 production for the project for the tax period being reported.

(4) Incremental production to be reported as post-1999 is the amount of production computed when the post-1999 ratio determined above is multiplied times the total incremental production for the quarter. The amount of non-incremental post-1999 production to be reported is determined by subtracting the amount of post-1999 incremental production from the total post-1999 production.

(5) The value for all production (incremental and non-incremental) in a project will be based upon an average price for the production sold from the project during the quarter.

(1) In determining whether a lease or unit has an average daily production of less than 60,000 cubic feet of natural gas per well, only those wells that produced natural gas during the prior calendar year shall be used in the calculation. For natural gas that is processed to remove natural gas liquids, the volume (i.e., cubic feet) used to calculate the average daily production herein will be the volume prior to any removal of the natural gas liquids.

(2) In determining whether a lease or unit has an average daily production of less than 15 barrels of crude oil per well for stripper qualification, or three barrels of crude oil or less per well for the stripper well exemption or stripper well bonus, only those wells that produced crude oil during the prior calendar year shall be used in the calculation.

(3) The operator must provide a stripper calculation for the previous calendar year to the department to qualify each oil stripper or natural gas stripper lease or unit each year when filing the return for the quarter ending in March to qualify the lease or unit as stripper for the current year.

(4) If a well or group of wells has qualified as an enhanced recovery project or an expanded enhanced recovery project, all production from the well or wells, including any incremental production, must be included as production for the purpose of determining if the well or wells qualify as stripper.

(1) For the purpose of this rule a lease or unit will be considered to be dually qualified if the lease or unit qualifies as an oil stripper and the wells are within an approved enhanced recovery project. If the wells are dually qualified, the tax rates for stripper, incremental and non-incremental may all apply.

(a) If the production for a quarter from a dually qualified lease or unit is less than 270 barrels (three barrels/day times 90 days in a calendar quarter) for each producing well in the lease or unit the tax rates in ARM 42.25.1809(1) (b) (ii) (C) or (1) (b) (ii) (D) apply.

(b) If the production for a quarter from a dually qualified lease or unit is less than 900 barrels (10 barrels/day times 90 days in a calendar quarter) for each producing well in the lease or unit the tax rates in ARM 42.25.1809(1) (b) (ii) (A) apply.

(c) If the production from each well in a dually qualified lease or unit is greater than 900 barrels for each producing well in the lease or unit the tax rates in ARM 42.25.1809(1) (b) (ii) (A) apply to the first 10 barrels, and if:

(i) The total production for the quarter from the dually qualified lease or unit is less than the "production decline rate" for the calendar quarter any production in excess of 900 barrels times the number of producing wells in the dually qualified lease or unit will be taxed at the rates in ARM 42.25.1809(1) (b) (ii) (B) . None of the production would be taxed at the incremental tax rates. Example: A dually qualified lease or unit has 3 producing wells in it and the "production decline rate" for the quarter is 5700 barrels. The actual production for the quarter is 5000 barrels. Therefore, 2700 barrels (3 wells times 900 barrels per well) would be taxed at the rates in ARM 42.25.1809(1) (b) (ii) (A) , and 2300 barrels (5000 barrels minus 2700 barrels) would be taxed at the rates in ARM 42.25.1809(1) (b) (ii) (B) .

(ii) The total production for the calendar quarter from the dually qualified lease or unit that is in excess of the "production decline rate" will be taxed as incremental. The tax rates in ARM 42.25.1809(1) (b) (iv) (A) will apply for secondary production, or the tax rates in ARM 42.25.1809(1) (b) (iv) (B) for tertiary production will apply.

Example: A dually qualified lease or unit has 5 producing wells in it and the "production decline

rate" for the quarter is 5700 barrels. The actual production for the quarter is 6000 barrels.

Therefore, 4500 barrels (5 wells times 900 barrels per well) would be taxed at the rates in

ARM 42.25.1809(1) (b) (ii) (A) , and 1200 barrels (1200 barrels plus 4500 barrels = 5700)

would be taxed at the rates in ARM 42.25.1809(1) (b) (ii) (B) , and 300 (6000-5700) barrels

would be taxed at the appropriate incremental tax rates in ARM 42.25.1809(1) (b) (iv) .

(1) Table I reflects the tax rates effective October 1, 2006 through September 30, 2016, as set forth in 15-36-304, MCA, and by the Montana Board of Oil and Gas Conservation by rule.

Table I - Effective through 9/30/2016

(2) Table II reflects the tax rates effective on October 1, 2016, as set forth in 15-36-304, MCA, and by the Montana Board of Oil and Gas Conservation in ARM 36.22.1242.

Table II - Effective 10/1/2016

(3) Section 82-11-131, MCA, provides for a maximum allowable tax rate of .3 percent of value. The rate enacted, up to the maximum allowable, is established by and subject to change by the Montana Board of Oil and Gas Conservation by rule.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

(1) All oil and gas production taxes collected after the date the tax was due will be distributed in accordance with the statutes and administrative rules governing the distribution of the tax in effect on the date the tax revenue is received.

(2) For all oil and gas production taxes refunded, the amount of the refund allocated to each governmental entity will be determined in accordance with the statutes and administrative rules governing the distribution of any tax revenue in effect on the date the refund is made to the taxpayer.

(3) In situations where all of the leases associated with taxes due or refunds as referred to in (1) or (2) are no longer operational, the department will use the most recent quarter in which at least one lease had production taxes paid to distribute the tax or make the refund.

(2) The incentive periods are applicable for qualifying production that occurred during the first 12 months of production of oil or natural gas from a well drilled after December 31, 1998, or the first 18 months of production of oil or natural gas from a horizontally completed well drilled after December 31, 1998. It may also mean a well that has not produced oil or natural gas during the five years immediately preceding the first month of qualifying production. Qualifying production does not include oil production from a horizontally recompleted well.

(2) The population information will be updated with the third quarter distribution, which is distributed in January, and continue to be used until the next yearly update.

(3) A qualifying county that has an incorporated city or town that is not included in the census must inform the department of revenue of that fact, and provide proof of incorporation along with the population information for that city or town.

(1) Qualifying production time period begins immediately after the last day of the month preceding the month when production first started. The qualifying production time period continues for 12 or 18 contiguous months, 12 for vertical production or 18 for horizontally completed wells.

(a) Example – A vertical oil or natural gas well first produces May 2010. The well will have a reduced tax rate as illustrated in 15-36-304, MCA for the months May 1, 2010, to April 30, 2011.

(2) The tax incentive applies to the total gross value of all oil or natural gas sold in the 12- or 18-month period. If the sales occur after the 12- or 18-month period nonqualifying production tax rates as described in 15-36-304, MCA apply.

(1) If natural gas is sold pursuant to an arm's-length contract at the wellhead, the contract price multiplied by the volume of natural gas will be accepted as the total gross value.

(2) If natural gas is sold in the absence of a contract the total gross value of the natural gas may be determined by reviewing comparable arm's-length contracts. The department will identify comparable arm's-length contracts utilizing factors including but not limited to; similar time, proximity to the location, similar duration, similar gas quality, and similar quantity of gas sold. Upon conducting a comparable arm's-length study, the department will attempt to identify comparable arms-length's contracts within the same field of the leases in question prior to using comparable arm's-length contracts from other fields.

(3) If natural gas is sold through a non-arm's-length contract at the well or wells and sold with an arm's-length contract further downstream of the well or wells, the total gross value of the natural gas may be determined at the delivery point with delivery price adjustments.

(1) DPA costs are reasonable and necessary costs incurred by the operator to bring the gas to the point of delivery. DPA costs must be documented, itemized, and increase the value of the gas.

(2) Allowable delivery price adjustment costs include but are not limited to:

(a) Costs of direct labor associated with the central facilities. Direct labor is not meant to include personnel in corporate or headquarter offices who are not directly involved in the actual on-site central facility operations;

(b) Costs of materials, supplies, maintenance, repairs, and utilities directly associated with the central facility;

(c) Property taxes paid on the central facility;

(d) Liability and casualty insurance directly paid on the central facilities;

(e) Depreciation of the central facility is allowed as a reduction in gross value or a delivery price adjustment. The department will allow the depreciation of the initial capital investment of the central facilities, determined on a straight-line basis for a period of ten consecutive years beginning the year in which the facility first began to operate. The department will also allow additional capital investments made to the central facilities after the initial capital investment determined on a straight-line basis for a period of ten consecutive years beginning the year in which the additional capital investment was acquired;

(f) A return on investment percentage will be allowed to the operator of the central facility provided a balance of the initial capital investment is available to be depreciated as calculated in accordance with (2)(e). The annual rate of return will consist of the undepreciated balance of the capital investment multiplied by Moody's Baa corporate bond rate. For example assume the following: both Company Y and Company X operate gas wells in Montana, both companies do not have arm's-length wellhead contracts, but rather delivered gas contracts well downstream of the wells, Company Y made an initial capital investment of a central facility asset (a gas processing plant) for $1,000,000 and the initial investment has not been fully depreciated ($800,000), Company Y sold the asset to Company X for $200,000 (Moody's Baa corporate rate is 3 percent), and Company X will be allowed a return on investment reduction of their gas value of 3 percent of the acquisition cost or 3 percent * $200,000 or $6,000.

(3) Unallowable delivery price adjustment costs include but not limited to:

(a) State and Federal income taxes, license taxes, sales taxes, fuel taxes, excise taxes, production taxes and other fees, including royalties are not allowable expenses.

(b) Acquisition costs cannot be deducted in the year incurred or capitalized, and amortized under this rule.

(c) Costs incurred in the normal lease separation of the natural gas are not allowed.

(d) No company overhead costs will be allowed.

(e) Indirect labor such as supervisory labor or office labor will not be allowed.

(f) No allocable costs that are not considered direct costs will be allowable.

(1) Deductions are allowable only to the extent that they represent directly related costs of the operator's central facilities and were actually incurred and paid.

(2) The Montana Oil and Gas Production Tax is not an income tax. Therefore, the delivery price adjustment rules do not allow the broad spectrum of deductions allowed under an income tax.

(1) Any delivery price adjustment or reduction in value will be disallowed if the operator does not keep adequate records or other proof to show the amount and purpose for the expense. To satisfy the adequate records requirement, there must be records maintained and supported by receipts, vouchers, or other documentary evidence.