Chapter 6 - Valuation of Natural Resources

Classification

Natural resource leaseholds and lands are classified for valuation and abstract purposes into three major categories:

1. Producing Mines
2. Producing Oil and Gas Leaseholds and Lands
3. Other Natural Resource Leaseholds and Lands (Excepted Mines)

Producing Mines

This classification includes all natural resource operations defined as producing mines pursuant to § 39-6-105, C.R.S., which had gross proceeds during the previous calendar year in excess of $5,000. Minerals extracted by such operations include, but are not limited to:

• Cadmium
• Copper
• Gold
• Iron
• Lead
• Molybdenum
• Silver
• Tin
• Tungsten
• Uranium
• Vanadium
• Zinc

Also included are oil shale mineral operations that mine oil shale rock for later extraction of kerogen (shale oil) through a retort process.

Producing Oil and Gas Leaseholds and Lands

All leaseholds and lands that produced oil and/or natural gas products, which were sold or transported from the production area during the previous calendar year, are included in this classification. Examples include leaseholds and lands producing carbon dioxide (CO₂) or other naturally occurring gases.

Also, included in this classification are oil shale operations which extract kerogen (shale oil) from in-place shale reserves using the in-situ or modified in-situ method.

Other Natural Resource Leaseholds and Lands

Natural resource lands, other than producing mines and oil and gas leaseholds and lands, should be included in this classification. It includes all mines excepted under § 39-6-104, C.R.S. Examples of mineral operations excepted from the producing mine statute are operations extracting:

• Asphaltum
• Coal
• Clay
• Dawsonite
• Dolomite
• Feldspar
• Fluorspar
• Ganister
• Granite
• Gravel
• Gypsum
• Limestone
• Peat
• Perlite
• Quartz
• Road Base
• Rock
• Sand
• Soda Ash (nahcolite)
• Stone
• Turquoise
• Volcanic Scoria

Also included in this classification are:

1. All natural resource operations extracting any product with gross proceeds during the previous calendar year of less than or equal to $5,000
2. Nonproducing patented mining claims
3. Nonproducing severed mineral interests

Producing Mines

The following subsections refer to the assessment of producing mines.

Statutory References

The statutes in article 6 of title 39, C.R.S., cover producing mines, nonproducing mines, and operations that extract products excepted from the producing mine definition.

In this article, specific terms are defined.

Definitions.

As used in this article, unless the context otherwise requires:
(1) "Mine" means one or more mining claims or acres of other land, including all excavations therein from which ores, metals, or mineral substances of every kind are removed, except drilled wells producing sulfur and oil, gas, and other liquid or gaseous hydrocarbons, and all mining improvements within such excavations, together with all rights and privileges thereunto appertaining.

(2) "Mining claims" means lode, placer, millsite and tunnelsite claims, whether entered for patent, patented, or unpatented, regardless of size or shape.

(3) "Ore" includes, without limitation, metallic and nonmetallic mineral substances of every kind, except those specifically excluded under section 39- 6-104.

(4) "Other land" means any parcel of real property which is not a mining claim.

§ 39-6-101, C.R.S.

Mines are also classified by statute.

Classification of mines.

All mines, except mines worked or operated primarily for coal, asphaltum, rock, limestone, dolomite, or other stone products, sand, gravel, clay, or earths, shall, for the purpose of valuation for assessment, be divided into two classes: Producing and nonproducing.

§ 39-6-104, C.R.S.

The terms, producing mines and nonproducing mines, are also defined by statute.

Producing mines defined.

All mines whose gross proceeds during the preceding calendar year have exceeded the amount of five thousand dollars shall be classified as producing mines, and all others shall be classified as nonproducing mines. Mines shall be classified in the manner provided for in this article regardless of the processing method, the ultimate use, or the consumption of the ores or minerals for which they are primarily worked or operated.

§ 39-6-105, C.R.S.

Additional statutes covering other important areas of producing mine assessment can be found in article 6 of title 39, C.R.S. and should be reviewed by the appraiser.

Mine Classification

The following minerals are included within the statutory producing mines classification.

• Molybdenum
• Precious Metals and Substances (platinum, gold, silver, diamonds)
• Base Metals (cadmium, copper, iron, lead, tin, tungsten, and zinc)
• Strategic Minerals (uranium, vanadium)
• Oil Shale (oil shale/retort)

For valuation of in-situ oil shale operations, refer to Producing Oil and Gas Leaseholds and Lands.

Colorado statutes define a producing mine as a mine whose gross proceeds exceeded five thousand dollars ($5,000) during the preceding calendar year. All other mines are considered nonproducing mines or excepted mines and are to be valued in the same manner as other real property.

A producing mine includes, as a unit, any contiguous mining property, tunnels, or other land owned or leased by the same person and used in any phase of the mine operation. Also within a mine excavation, improvements and fixtures associated with water and drainage systems, ventilation systems, and electrical power systems are included as mining improvements. They are not valued separately.

Not included in the producing mine value and subject to separate assessment are improvements, structures, and building system fixtures located outside of the mine portal or excavation, all machinery and equipment, and any other personal property. Milling or smelting operations contiguous to the mining operation are not to be included in the producing mine valuation but are to be valued in the same manner as other real property.

All other claims and other lands not included in the producing mine are to be valued in the same manner as other real property on an acreage basis, regardless of surface contiguity.

Mine Discovery

Several good sources for the discovery of and information about producing mines are:

1. The Colorado Division of Reclamation, Mining, and Safety (DRMS), (formerly Division of Minerals and Geology) headquartered in Denver, is the best source for the discovery of pending and ongoing natural resource operations and maintains information on mining operations statewide. The reports contain information on locations, acreages, reserve lives and mining plans. The records of the DRMS are open for public inspection. The address is:
   
   Division of Reclamation, Mining, and Safety
   Centennial Building
   1313 Sherman Street, Room 215
   Denver, CO 80203
   Telephone: 303-866-3567
   Division of Reclamation, Mining, and Safety Website
2. The Colorado Geological Survey publishes maps, geological reports and general mine data on most natural resources within Colorado. Most of these resources are available online or through their bookstore. For more information, contact them directly at:
   
   Colorado Geological Survey
   Colorado School of Mines
   Moly Building
   1801 Moly Road
   Golden, CO 80401
   Telephone: 303-384-2655
   Colorado Geological Survey Website
3. The Colorado State Land Board handles the leasing of all natural resource operations on state land. Its office contains information on the type of product(s) mined, royalty rates, lessor's name, status of property, acres under lease, and location. The address is:
   
   Colorado State Land Board
   1127 Sherman Street, Suite 300
   Denver, CO 80203
   Telephone: 303-866-3454
   Colorado State Land Board Website

Mining Valuation Definitions

Statutory Definitions

In the valuation of producing mines, certain statutory definitions play an important part. The definitions, taken from § 39-6-106, C.R.S., follow:

Gross Value: The gross value from production of the ore extracted during said calendar year, which means and includes the amount for which ore or the first salable products and/or by-products derived therefrom were or could be sold by the owner or operator of a mine, as determined by actual gross selling prices.

Gross Proceeds: The gross proceeds from production of such ore, which means and includes the value of the ore immediately after extraction, which value may be determined by deducting from gross value all costs of treatment, reduction, transportation, and sale of such ore or the first saleable products and/or by-products derived therefrom.

Net Proceeds: The net proceeds from production of such ore, which means and includes the amount determined by deducting from the gross proceeds all costs of extracting such ore.

Other Definitions

Additional definitions have been developed by the Division for use in understanding and implementing producing mine valuation statutes and assessment procedures, § 39-6-109(3), C.R.S.

Agent: One who is authorized to act for or in place of another; a representative. (Black's Law Dictionary - 7th Edition)

An agent does not include salaried or hourly paid employees of a company or corporation.

Allocation: Recovery of the historical cost of capital (fixed) assets based on the life of the asset. An annual deduction for an amortized allocated fixed asset cost may be taken as a cost of production.

Capital Assets: Also called Fixed Assets. Capital assets are tangible assets of a permanent nature used to produce income. Capital assets are defined as improvements, fixtures, or equipment with an economic life in excess of one year.

For the purposes of these procedures, fixed assets consist of buildings, structures, fixtures, and personal property. Asset costs for land, including minerals rights, are not allowed for amortized cost allocation or depletion deduction as a cost of production.

Development Costs: Costs expended by the owner or operator of an operating producing mine to develop or prepare an ore body prior to extraction of the ore or unprocessed material. Expenditures, including government mandated costs, fees, and permit costs incurred in development of the ore body are considered development costs. Exploration costs are not allowed for inclusion or deduction as development costs.

Exploration Costs: Expenses incurred in prospecting, assaying, locating, or other activities to ascertain whether a mineral exists and to determine whether the mineral is physically and economically feasible to mine.

Doré Bullion: An impure alloy of silver or gold produced at a mine.

Margin Costs: Also called margin or profit, margin costs are allocated production costs or expenses reflecting direct, imputed, or implied profit accruing to the ore, unprocessed material, or refined products of the producing mine. Margin can accrue in any phase of the operation, including the treatment, reduction, transportation, sale, or extraction process.

Off-site Costs: These are expenses, either directly or indirectly associated with a producing mine, that are incurred at a location beyond the borders of the producing mine site. Allocated off-site costs, exclusive of compensation of officers or agents not actively and continuously engaged about the mine, that are directly associated with the extraction, treatment, reduction, transportation, and sale of the ore or first salable product(s) are allowed.

Officer: A person elected or appointed by the board of directors to manage the daily operations of a corporation, such as a CEO, president, or treasurer. (Black's Law Dictionary - 7th Edition)

Pre-production Development Costs: These are costs expended by the owner or operator in preparation for start-up of the mine. Expenditures, including government mandated costs, fees, and permit costs incurred in development of the mining property after a decision to build the mine has been made are considered pre-production development costs.

Exploration costs incurred to ascertain whether a mineral exists and to determine whether the mineral is physically and economically feasible to mine are not allowed for inclusion or deduction as pre-production costs.

Mine Taxpayer Filing Requirements

The person owning or operating a producing mine is required to file the following information
with the county assessor by April 15th, § 39-6-106(1), C.R.S.:

1. List of contiguous mining claims or other lands and their acreages
2. Name and address of the owner and operator
3. Total number of acres contained in the mine and, if such mine is located in more than one county, the total number of acres contained in such mine in each county
   
   If the taxpayer declares, according to § 39-6-106(1), C.R.S., the number of acres in each county, the taxpayer is not required, under § 39-6-113(4), C.R.S., to file any additional statements or declarations regarding mine acreage allocations, if no changes have occurred since the original statement was filed.
    
4. Tons of ore extracted during the preceding calendar year and, if the value of the products derived from the ore is used to determine gross value, the number of tons, pounds, or ounces of products derived from the ore
5. Gross value of production
6. Cost of treatment, reduction, transportation, and sale
7. Gross proceeds from production
8. Cost of extraction
9. Net proceeds from production

As stated in § 39-6-106(1.4), C.R.S., the owner or operator of a producing mine may request permission from the Board of County Commissioners in each county where the mine is located to state an average figure for items 4 through 9 listed above.

Specifically, the owner or operator may select any three (3), five (5), or ten (10) year reporting period (averaging period) immediately preceding January 1 of the year in which the declaration schedule is filed. This request must be in writing and filed at least 45 days prior to the statutory April 15 filing date (by March 2) of the year in which the declaration schedule is filed. A copy of the request must be attached to the declaration schedule filed by the owner or operator no later than April 15 of each year. The same reporting period must be used for all annual statements pertaining to a particular mine.

At least 30 days prior to the statutory April 15 filing date (by March 16), the county commissioners of each county must approve or deny the request to submit three, five, or ten year averaged figures. Failure of the commissioners to approve or deny the request by March 16th is deemed an approval of the request.

Producing mine owners or operators that have elected to use a three, five, or ten year averaging period may submit restated production cost figures that incorporate additional allowed deductions pursuant to current Colorado statutes, providing these procedures are used for the prior years within the selected reporting period.

Once approval has been given, the owner or operator must file all declaration schedules for subsequent assessment years using the same reporting method (averaging period). The reporting method can only be changed upon approval of the Board of County Commissioners in every county where the mine is located. Failure of the commissioners to approve or deny the request for a change in the reporting period by March 16th is deemed an approval of the request.

Regardless of whether approval has been received, the owner or operator of the producing mine must file the declaration schedule containing the required real and personal property information by the statutory April 15 filing date. The same reporting method must be used on all annual statements and declaration schedules filed in a single year pertaining to a particular mine.

Allowed and Non-Allowed Costs of Production

Mine Allowed Costs of Production

1. Treatment Costs - costs incurred subsequent to mining but before sale. They include costs of crushing, grinding, concentrating, separating, agglomeration or any other form of processing performed prior to smelting. If the mining company does not own the mill or have any interest in it, then use the contract price paid for milling service. Any allocated on-site general and administrative costs directly tied to the treatment process would also be included as treatment costs.
2. Reduction Costs - costs incurred subsequent to milling or other initial processing of the ore. Reduction costs include the smelting or conversion of the ore to its base product or products. The cost of reduction for precious metals is the total charge by the smelter for the production of refined products from Doré bullion. This may include transportation of bullion to the smelter, insurance, and smelter charges. Any allocated on-site general and administrative costs directly tied to the reduction process would also be included as reduction costs.
3. Transportation Costs - include the movement of the ore from the mine portal (mine mouth) to the point of sale. The process of transporting ore from the mine to the crusher is allowable if not previously deducted elsewhere. If the point of sale is after treatment and reduction, then related transportation costs should be allowed. Any allocated onsite general and administrative costs directly tied to the transportation of the ore or products to the point of sale would also be included.
   
   Haulage costs within the mine, from the mine face to the mine portal, are extraction costs and should not be included here.
   
   Transportation costs, in the case of leach treatment of gold ore, could include trucking of ore from crusher to leach pad or conveyor transport of ore from the crusher to the leach vats. No additional deduction is allowed if the cost of transportation of the ore through the leach process has already been included as a treatment cost.
    
4. Sale Costs - include costs of selling the marketable products. These costs should be itemized. If Doré bullion is sold, costs could include transportation, insurance and sampling. If refined products are sold, costs could include storage fees, insurance, and sampling. Sales commissions paid prior to the point of sale are an allowable cost of sale. Any on-site allocated general and administrative costs directly tied to the sale of the ore or products at the point of sale would also be included.
5. Extraction Costs - extraction costs are direct mining costs. These are the costs involved in mining the undisturbed ore and transporting it to the mine portal.
   
   Amortized pre-production development costs expended by the owner or operator in preparation for start-up of the mine are allowable costs of extraction. Exploration costs incurred to ascertain whether a mineral exists, and to determine whether it is physically and economically feasible to mine, are not allowed for deduction. Severance taxes, direct property taxes on the producing mine exclusive of machinery and equipment and surface improvements, and royalty expenses to exempt entities are allowable costs of extraction.
   
   Any allocated, on-site general and administrative costs directly tied to the extraction operation would also be included.
    
6. Other Miscellaneous Costs - off-site general and administrative costs, including employee salaries, wages, and benefits, are allowed if they are properly allocated and can be directly tied to the pre-production development cost of the mine site or the treatment, reduction, transportation, or sale of the ore, concentrate, or first salable product. If off-site general and administrative costs are allocated, the allocation methodology must be disclosed with the declared costs.
   
   A detailed listing of itemized costs with associated narrative descriptions of those costs should be obtained and reviewed prior to allowing any deduction. Off-site costs that are not directly related to the mining operation are not allowed.
    
7. Allocation of Capital (Fixed) Asset Costs - a deduction for amortized, allocated cost of fixed assets can be taken as a cost of production. However, fixed assets must be categorized as treatment, reduction, transportation, and sale assets, or as extraction assets prior to deduction. Deduction for amortized allocated cost of fixed assets may be included as a component of individual treatment, reduction, transportation, sales, and extraction costs, as reported by the taxpayer, but must reflect only those fixed assets that are currently in use in those production processes.
   
   A deduction for an amortized allocated cost of treatment, transportation, reduction, and sale assets can be taken as a cost of production from the gross value of production in determining gross proceeds value. A deduction for an amortized allocated cost of extraction assets also can be taken as a cost of production from gross proceeds value in determining net proceeds value.
   
   Deduction for amortized allocated cost of fixed assets is allowed for producing mine valuations beginning in the 1994 assessment year. As specified in § 39-6-106(1.7)(b)(II), C.R.S., all accumulated depreciation that was previously deducted, or could have been deducted prior to 1994, cannot be listed for additional deduction as a cost of a fixed asset.
   
   Amortization of pre-production development costs is allowed for producing mine valuations established for the 1994 assessment year. All accumulated amortized preproduction amounts that were previously deducted, or could have been deducted prior to 1994, cannot be listed for additional deduction as a cost of a fixed asset.

Examples of Allocation of Asset Cost Methodologies

For allocation of asset costs such as buildings, structures, fixtures, and pre-production development costs, either a straight-line method over the estimated life of the operation or a units-of-production method over the life of the reserve is acceptable.

Example:

Producing Mine

Straight-line Method

Units-of-Production Method

Assuming no additions or retirements, the amount subject to allocation should be reduced each year by the yearly allocation deduction taken by the producing mine owner or operator. However, the total amount subject to allocation may increase or decrease from year to year as assets are constructed, acquired, abandoned, or permanently retired.

For allocation of personal property costs such as machinery, equipment, furnishings, and other assets that are classified as personal property, a straight-line allocation method over the estimated life of the property is acceptable.

Example:

Producing Mine

¹Amount subject to allocation (includes acquisition cost, installation cost, sales/use tax, and freight of item to the point of installation)

Remaining Economic life of personal property items 8 years

Straight-line Method

To determine the appropriate allocation deduction, personal property items should be grouped together by asset life. The deduction amounts for each asset life group can be calculated and then added together for the final allocation deduction(s).

Assuming no additions or retirements, the amount subject to allocation should be reduced each year by the yearly allocation deduction taken by the producing mine owner or operator. However, the total amount subject to allocation may increase or decrease from year to year as assets are acquired, salvaged, abandoned, or permanently retired.

Deduction for allocated asset costs and pre-production development costs must begin in the first calendar year after production has commenced. Unless otherwise shown here, rules contained within the Generally Accepted Accounting Principles (GAAP) will govern the application of amortization of these costs.

Non-Allowed Costs of Mine Production

The following costs are not allowable as costs of production:

1. Interest Expense - interest expense is the cost of borrowing money. Management can control this cost by using various financial techniques.
2. Income Taxes - income taxes are an expense based on the profitability of an operation and are not related to the value of the producing mine leaseholds and lands.
3. Depletion Allowance - this is a deduction allowed by the IRS for income tax purposes.
4. Dividend Expense - expenses paid to shareholders of a mining corporation are not directly related to the value of the producing mine leaseholds and lands.
5. Incurred or Amortized Exploration Costs Prior to Production - costs or expenses incurred to ascertain whether a mineral exists and if it is physically and economically feasible to mine. These costs are generally incurred prior to the decision to begin development of the mine. Since such costs are not directly associated with preproduction development activities or actual production, they are not deductible.
6. Royalty Expenses to Taxable Entities - royalties are an expense related to the right to extract minerals. Although not deductible, this right is included in the bundle of rights associated with the mine valuation, which is valued under the Gross/Net Proceeds formula.
7. Compensation of Officers and Agents not actively and continuously engaged about the Mine - deduction of these costs (including benefits and commissions of officers and agents) are prohibited by §§ 39-6-106(1)(f) and 39-6-106(1.7)(a)(I)(C), C.R.S.
8. Costs to Acquire Land or Subsurface Mineral Rights - asset costs for land, including minerals rights, are not allowed for amortized cost allocation deduction as a cost of production.
9. Margin Costs - direct, indirect, or imputed profit that accrues to the extraction, treatment, transportation, or sale of the ore or products derived from the ore are not allowed. Deduction of this cost is prohibited by § 39-6-106(1.7)(b)(I), C.R.S.
10. Non-Allocated General and Administrative Expenses - any general and administrative expenses that cannot be directly tied to the extraction, sale, reduction, treatment, or transportation cannot be deducted.

Any other costs or expenses not directly related to the extraction, transportation, treatment, reduction, or sale of the ore, concentrate, or product cannot be deducted.

Confidentiality of Taxpayer Information

The natural resources property declaration schedules and appraisal records are used for both real and personal property data. Since confidential real and personal property information is contained on both the front and back of these declaration schedules, requests for non-confidential information should be directed to other public agencies which have access to this information and have the means of disclosing it to the public without divulging confidential information, §§ 39-5-120 and 24-72-204(3)(a)(IV), C.R.S. Examples of these agencies might include, but are not limited to, the Colorado Division of Reclamation, Mining, and Safety or the Federal Bureau of Land Management.

Valuation of Producing Mines

Section 3 of article X of the Colorado Constitution requires that the value of a producing mine be based on the value of the unprocessed material. The gross (or net) proceeds amount represents the value of the unprocessed material immediately after extraction. This amount is the statutorily prescribed measure of value of the producing mine leaseholds and lands and any mining improvements within the mine excavation.

Mining improvements may include such real property improvements within the mine excavation such as roof supports, shafts, raises, drifts, tunnels, adits, stopes, and cutouts. Improvements and fixtures within a mine excavation that are associated with water and drainage systems, ventilation systems, and electrical power systems are also included as mining improvements and are not separately valued.

Not included in the producing mine value and subject to separate assessment are improvements, structures, and building system fixtures located outside of the mine portal or excavation, all machinery and equipment, and any other personal property.

The following are the statutory steps in the valuation of a mine by gross or net proceeds:

Step #1 Determine the gross value of the ore extracted during the preceding calendar year or approved reporting period.

Gross value is the amount for which the ore or first salable product derived therefrom was sold or could have been sold. If there is an established market value for the type of ore mined, this value may be shown, even if it is not actually sold as ore. If part or all of the ore mined was not sold, it should be valued at prevailing prices for the year of production or approved reporting period.

Step #2 Deduct all costs of treatment, reduction, transportation, and sale to estimate gross proceeds. Refer to Allowed and Non-Allowed Costs of Production.

Step #3 Deduct the costs of extraction from the gross proceeds to estimate net proceeds. Extraction costs are direct mining costs. These are the costs involved in mining the undisturbed ore and transporting it to the mine portal. Refer to Allowed and Non-Allowed Costs of Production.

Step #4 Determine current valuation for assessment. Determine the greater of the following:

25% of gross proceeds
100% of net proceeds

The greater of the two numbers is the valuation for assessment of the producing mine. If both numbers are negative, additional review of allowed deductions in the producing mine formula is necessary.

An example of gross or net proceeds valuation based on information in a sample declaration for a producing mine:

Statement of Production

CORRELATION

25% of current gross proceeds = $ 17,000
100% of net proceeds = $ (33,000)
Valuation For Assessment = $ 17,000

If the mine is located in more than one taxing jurisdiction, divide the valuation between the jurisdictions in proportion to the number of acres contained in the mine located in each jurisdiction. If the mine is located in more than one county, the mine must file a consolidated statement with the assessor of each county.

Mine Review and Audit of Books and Records

Under § 39-6-109, C.R.S., the assessor has the right to examine and review the books and records of any owner or operator of a producing mine to verify the information contained within the taxpayer's property declaration statement.

Assessor to examine books, records.

(1) The assessor has the authority and right at any time to examine the books, accounts, and records of any person owning, managing, or operating a producing mine in order to verify the statement filed by such person, and, if from such examination the assessor finds such statement or any material part thereof to be willfully false or misleading, the assessor shall proceed to value such producing mine for assessment as though no such statement had been filed.

(2) Upon the request of the assessor, the owner or operator of a producing mine shall provide to the assessor all documentation supporting the amounts reported on the statement filed by such owner or operator.

§ 39-6-109, C.R.S.

Omitted valuation, determined as a result of incorrect, misstated, or omitted information required under § 39-6-106, C.R.S., is considered omitted property and can be placed on the tax roll within six years, § 39-10-101(2)(b), C.R.S.

Colorado Revised Statute § 39-6-109(3) requires the Division to develop procedures for the review and auditing of the declaration schedule and the assessor's examination of the books and records of the producing mine. These procedures provide instruction for review of the books, records, and recommended documentation filed with the county assessor pursuant to § 39-6-106(1), C.R.S., for verification of the amounts declared for a producing mine.

All county assessors, assessors’ office staff, and their agents must utilize the procedures and instructions. For the purpose of these review and audit procedures, "agents" are defined as any person or business that contracts with the county to perform reviews or audits of producing mines to determine if the amounts declared to the county, by owners or operators of producing mines, are correct.

The process by which the books and records of a producing mine are examined consists of two stages; a "review" and, if necessary, an "audit."

Definition of "Review" and "Audit"

A review is defined as an analysis of the declared producing mine production volume, the gross value of ore or product produced, and summary reports of production costs for treatment, reduction, transportation, sales, and extraction, and yearly allocation amounts of fixed assets. The beginning point of a review is the DS 628, Producing Mine Real and Personal Property Declaration, filed by the producing mine for the selected reporting method (averaging period). A review is generally performed at the assessor's office or a site mutually agreed to between the taxpayer and assessor.

An audit is defined as an examination and analysis of taxpayer's records including source documents regarding production volumes, production value, production costs, and fixed asset allocations. Most audits are performed at the producing mine site or site where the operation and financial accounting records are kept.

General Review and Audit Procedures

Counties are permitted to establish reasonable review and audit procedures that they feel would fairly and accurately determine if any discrepancy exists between the taxpayer's declared information and amounts verified through the books and records of the company or through other information sources utilized by the county. The following must be included in the county's review program:

1. The county assessor must provide the taxpayer with a letter, by certified mail, indicating that a “review” of that taxpayer's producing mine declaration has been conducted. The letter must include:
   1. The production year under review. If an averaging period has been selected, the years used by the owner or operator in the selected period.
   2. Any requests for additional information regarding the taxpayer's reporting discrepancy.
   3. A listing of the taxpayer's rights regarding the "review."
2. If the taxpayer does not provide the requested information or refuses to make the information available, the assessor may:
   1. File in District Court under § 39-5-119, C.R.S., or
   2. Issue a Best Information Available (BIA) assessment.

Prior to a review, it is recommended that the assessor obtain the following documentation:

1. A current Chart of Accounts.
2. A narrative explanation of how the producing mine is operated.
   
   Specifically, the following explanations should be requested:
   1. How the ore is extracted.
   2. How the ore is transported from the mine face to the portal.
   3. An explanation of the process used for treatment of the ore.
   4. If the ore is reduced or smelted prior to sale, an explanation of the process used for treatment of the ore.
   5. How the ore and/or related products are transported through the treatment and reduction processes.
   6. The point of sale of the ore or related products, and how the ore or products are transported and sold.
3. Financial information consisting of a summary of functional cost control accounts listed by function that will balance with the production volume figures, gross value amounts, or production costs declared for the producing mine.
   
   This summary should have the appropriate financial account number(s) listed for each income or expense item or category listed.
    
4. A summary report, by asset type, of all fixed assets that are subject to depreciation.
   
   This summary report should contain the fixed asset historical cost, subsequent additions and retirements, accumulated depreciation, and remaining asset cost subject to depreciation. The assessor should also request documentation of the method of depreciation used and the life established for each of the asset types.
   
   As a reminder, a deduction for amortized allocated cost of fixed assets is allowed for producing mine valuations established for the 1994 assessment year. All accumulated depreciation that was previously deducted, or could have been deducted, prior to 1994 cannot be listed for additional deduction. Only amounts based on allocated cost amortization methods set forth in these procedures will be allowed for deduction.
    
5. A summary report of all pre-production development costs expended by the owner or operator in preparation for start-up of the mine.
   
   This summary report should contain all expenditures incurred in development of the mining property after a decision to build the mine has been determined.

All reports should be prepared and examined to verify that only allowable costs, as specified in Colorado Statutes and these procedures, are listed for deduction and review.

During a review, the assessor should be concerned with an analysis of the filed declaration schedule and requested summary reports. Comparison with schedules and reports from past years may be beneficial. In all cases, the producing mine owner or operator should be allowed adequate time to provide explanations of any discrepancies or concerns by the county regarding the declared amounts.

Prior to an audit, it is recommended that the assessor notify the owner or operator of the specific gross value or production cost items under analysis.

Auditing books and records will generally require a trip to the producing mine site or the site where the operation and financial accounting records are kept. An appointment for the audit should be made prior to visiting the site to avoid disrupting the mining operation.

When the audit is completed, the assessor should notify the owner or operator in writing of the results of the audit and any impact to the production volume, gross value of production, and production expenses declared by the producing mine. The producing mine owners or operators should also be advised of their right to pursue their administrative remedies in accordance with Colorado statutory provisions.

Mine Taxpayer "Review" and "Audit" Rights

The following rights must be provided in writing to all taxpayers subject to a producing mine
"review" or "audit" by the county:

1. At the request of the taxpayer, the county must schedule a meeting to discuss the scope of the review and/or audit by the county and receive any further information or response from the taxpayer.
2. Taxpayers must have at least 15 days to respond to the "review" notification letter and to provide additional information to the county regarding concerns of the county and any request of additional financial records. The assessor may grant additional time at the request of the taxpayer, if deemed necessary.

All information and documents submitted in response to a review and/or audit request are to be considered confidential, under the provisions of §§ 39-5-120 and 24-72-204(3)(a)(IV), C.R.S. All assessors, employees of the assessor office, and outside agents of the county are bound by these statutory provisions.

Division Review of County Review and Audit Procedures

Counties should follow the above procedures when reviewing or auditing taxpayer producing mine declarations. If the county wishes to depart from one or more of the review or audit procedures, the county should submit their changes to the Division for review prior to implementation.

Level of Value for Producing Mines

Producing mines are to be valued at the current value, according to § 39-1-104(12)(a), C.R.S., using the previous year's production information or a three, five, or ten year average of production information, § 39-6-106(1.4), C.R.S.

Producing Mines’ Water Treatment Facilities

In 1996, a new subsection § 39-1-103(16), C.R.S., was added setting forth the valuation procedures to be used for valuation of real and personal property of a superfund water treatment facility that is constructed as part of a superfund site agreement with the federal government or the state of Colorado or any of its political subdivisions.

Specifically, this statute mandates that for valuation of real and personal property of qualified water treatment facilities, the value determined from the income approach to appraisal is the upper limit of value under the following circumstances:

1. The term “superfund water treatment facility” is defined as real and personal property installed and constructed pursuant to an agreement with or order of the State of Colorado, United States Government, or any political subdivision thereof to satisfy the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), as amended.
2. The facility must be operated for the purpose of eliminating, reducing, controlling, or disposing of pollutants, as defined in § 25-8-103(15), C.R.S., that could alter the physical, chemical, biological, or radiological integrity of state waters.
3. The income approach must be applied to actual income generated by the facility during the calendar year preceding the assessment date capitalized at an annual rate of 10%.

The cost and market approaches to appraisal must be considered, but can only be used if the resulting value is less than the value determined from the income approach.

Producing Oil and Gas Leaseholds and Lands

Statutory References

Section § 39-1-103, C.R.S., specifies that producing oil or gas leaseholds and lands are valued according to article 7 of title 39, C.R.S.

Actual value determined - when.

(2) The valuation for assessment of leaseholds and lands producing oil or gas shall be determined as provided in article 7 of this title.

§ 39-1-103, C.R.S.

Article 7 covers the listing, valuation, and assessment of producing oil and gas leaseholds and lands.

Valuation:

Valuation for assessment.

(1) Except as provided in subsection (2) of this section, on the basis of the information contained in such statement, the assessor shall value such oil and gas leaseholds and lands for assessment, as real property, at an amount equal to eighty-seven and one-half percent of:

(a) The selling price of the oil or gas sold from each wellhead during the preceding calendar year, after excluding the selling price of all oil or gas delivered to the United States government or any agency thereof, the state of Colorado or any agency thereof, or any political subdivision of the state as royalty during the preceding calendar year;

(b) The selling price of oil or gas sold in the same field area for oil or gas transported from the premises which is not sold during the preceding calendar year, after excluding the selling price of all oil or gas delivered to the United States government or any agency thereof, the state of Colorado or any agency thereof, or any political subdivision of the state as royalty during the preceding calendar year.

§ 39-7-102, C.R.S.

The valuation of leaseholds and lands that use secondary and tertiary recovery is the same as above, except that the assessment rate to be used is seventy-five percent (75%). Secondary and tertiary recovery are defined under Definitions Pertaining to Oil and Gas Leaseholds and Lands Valuation, found later in the chapter.

Oil and Gas Classification

Classification of oil and gas leaseholds and lands includes all drilled wells producing any kind of petroleum or natural gas product such as oil, gas, helium, or carbon dioxide. Sulfur that is collected and sold as a by-product of the processing operation is also included. The classification includes all leasehold wells on lands owned by federal, state, or lesser governmental entities. Oil and gas classification also includes oil shale projects wherein the kerogen (shale oil) is extracted through the “in situ” process. In the “in situ” process, a portion of the shale deposit is mined out. The rest is fractured with explosives or by other means to create a highly permeable zone through which hot fluids can be circulated. For valuation of retort oil shale operations refer to the Producing Mines topic in this chapter.

Oil and Gas Discovery

The primary source of discovery is the Colorado Energy and Carbon Management Commission (ECMC) website. See Addendum 6-H, Instructions for Accessing the ECMC Website. The ECMC can also be contacted directly at:

Colorado Energy and Carbon Management Commission
The Chancery Building
1120 Lincoln Street, Suite 801
Denver, CO 80203
Phone: (303) 894-2100

Oil and Gas Taxpayer Filing Requirements

Section 39-7-101, C.R.S., requires every operator or, if there is no operator, owner of any oil and gas leasehold or lands in the state to file a statement with the county assessor by April 15th of each year. The statement is an Oil and Gas Real and Personal Property Declaration Schedule, DS 658, which must be sent by the assessor to every known operator/owner in the county as soon after January 1 as possible. Pursuant to §§ 39-7-110 and 39-10-106(2), C.R.S., the operator, or owner who filed the statement with the county assessor, is the taxpayer, Colorado Property Tax Administrator v. CO₂ Committee, Inc., (publish pending).

The DS 658 applies to any oil and gas leaseholds or lands that are producing or capable of producing on the assessment date, including wells that produced the prior year but were shut in and capped or plugged and abandoned prior to the current assessment date. The DS 658 must include:

1. The location of the wellsite and name of the well
2. The name, address and fractional interest ownership of the operator
3. The quantity of oil measured in barrels (Bbls) and/or the quantity of gas per thousand cubic feet (Mcf), or per million British Thermal Units (MMBTU), sold or transported from the premises during the preceding calendar year
4. The amount of royalties paid in cash or product to the United States government, state of Colorado, or any lesser governmental entity
5. The netback wellhead selling price of all oil and gas sold or transported from the premises during the preceding calendar year
6. The name, address, and fractional interest of each interest owner taking production in kind and the proportionate share of total unit revenue attributable to each interest owner who is taking production in kind

If the taxpayer is the owner of record as of January 1, and had purchased the well during the prior year, the taxpayer is responsible to report all production for the prior year, and is liable for the taxes on the leasehold and land based on the prior year’s production for the entire year. Any proration of the tax liability for the benefit of the owner of record should have occurred between the owner of record and the previous owner(s) at closing.

Whenever oil and gas leaseholds or lands are located in more than one county, the production value is assigned to the county in which the wellhead is located, § 39-7-107(1), C.R.S. A separate statement is filed with the assessor of each affected county, § 39-7-107(3), C.R.S.

Whenever a group of contiguous leaseholds or lands is operated as a unit (production unit, unitized field) in more than one county, the person making the statement required under § 39- 7-101, C.R.S., shall assign to each wellhead the production value from the unit as is assigned by the unit agreement, § 39-7-107(2), C.R.S. A separate statement is filed with the assessor of each affected county, § 39-7-107(3), C.R.S.

Methods of reporting such as computer printouts or electronic spreadsheet files (if electronic spreadsheets have been approved for use by the assessor) are acceptable provided the information is segregated by well and is accompanied by one signed DS 658.

Should the owner or operator, agent, or person placed in control of the wellsite or lease by the owner or operator, fail or refuse to file a statement, the assessor may impose on the owner or operator a late filing penalty in the amount of one hundred dollars ($100) per calendar day that the statement is delinquent. At the sole discretion of the assessor, an extension may be granted without charge for the filing of the statement. The length of the extension is also within the discretion of the assessor, § 39-7-101(2), C.R.S.

The assessor may also value the property based on the best information available to and obtainable by the assessor, § 39-7-104, C.R.S. In addition, assessors have the authority and right to examine the books, accounts, and records of anyone owning or operating oil and gas leaseholds and lands in order to verify the statement filed. If the statement is found to be willfully false, misleading, or incomplete, the assessor may utilize the best information available (BIA) to determine the value for assessment as though no statement had been filed, § 39-7-105, C.R.S.

Reporting of Take-in-Kind Production

Any non-operating interest owner who received "Take-In-Kind" (TIK) revenues for oil and gas production taken in kind during the preceding calendar year may submit a TIK report to the unit operator. The TIK report describes the actual net taxable revenues and the actual exempt revenues received, but netted back to the wellhead, by the non-operating interest owner during the preceding calendar year. The TIK report is sent by certified mail and is received by the unit operator on or before March 15 of the current assessment year. Unit operators use the information to determine "selling price at the wellhead" for TIK production reported by non-operating interest owners, § 39-7-101(1.5), C.R.S.

If any non-operating interest owner fails to provide the TIK report to the unit operator by March 15 of the current assessment year, then the unit operator's selling price per unit of production at the wellhead is used by the unit operator to value the non-reporting, non-operating interest owner's TIK production, § 39-7-101(1.5) C.R.S.

If the operator had more than one selling price for a product during the preceding year, then the Division recommends using a weighted average selling price for the product. The weighted average selling price for each product is calculated by dividing the operator's total revenues for each product by the production volume for each product. The operator's weighted average selling price for a product is then multiplied by the TIK owner's share of production for that product.

If an oil and gas price and production audit, as described later in the chapter, discloses a problem with the net taxable revenues reported by the fractional interest owner, then the unit operator is not liable for any tax or any penalty interest levied against any amount of TIK production, § 39-10-106(4)(b)(IV), C.R.S.

Take-In-Kind usually applies to gas. It is rare for liquids (Oil, Condensate, NGLs) to be Take-In-Kind. Take-In-Kind should not be confused with percent of proceeds or processing fees, both of which are associated with processing plants that have no interest in the subject well.

A common example would have two gas working well interest owners; Company A and Company B, with Company A being the well operator. Company B feels they have more expertise at selling gas and chooses to market their own share. Often Company B would also market the shares of royalty owners they brought into the well. In the following calendar year, Company B must submit a TIK report to Company A on or before March 15th.

Gas Used Prior to the Point of Sale

Regarding gas used either at the wellsite or off-site prior to the point of sale, owners or
operators are permitted to:

1. Report the gas as “sold gas” in which a deduction may be taken as a fuel cost related to processing, transporting, or manufacturing the oil or gas to the point of sale.
   OR
2. Not report the gas as “sold gas” as long as no deduction is taken for production gas used on or off-site related to processing, transporting, or manufacturing the oil or gas to the point of sale.

Owners or operators are strongly encouraged to advise the assessor if any gas used on the lease is not being reported as sold gas on the DS 658 Oil and Gas Leaseholds and Lands Declaration Schedule.

Oil and Gas Leaseholds and Lands Valuation Definitions

Bona Fide Sale: “a sale made by a seller in good faith, for valuable consideration, and without notice of a defect in title or any other reason not to hold the sale.” (Black’s Law Dictionary, 7th Edition)

For oil and gas netback valuation, the Division considers an arm’s length sale between unrelated parties to be a bona fide sale. Sales between related parties are not considered to be arm’s length transactions.

Downstream: any activity or process that occurs to the oil or gas product immediately beyond the casinghead/tubinghead.

Exempt Interest: any interest owned by the United States, the State of Colorado, or any political subdivision of the State of Colorado.

Field: a grouping of wells on or related to a single reservoir, or a grouping of wells on multiple reservoirs related to the same geological formation.

Flowlines: small, surface pipelines through which oil or gas travels from a wellhead to wellsite equipment or to a tank battery.

Gathering: the movement, of oil or gas products by separate and individual pipelines, of a relatively small size, to a point of accumulation, dehydration, compression, separation, heating/treating, off-site storage, or further processing. For the purposes of these procedures, "Gathering" is included within the term "Transportation."

Gross Lease Revenues: revenues received by the taxpayer from the bona fide, arm’s length sale of oil and gas products to the first purchaser.

On-site: any activity that involves equipment located within the area of the wellsite. Typical wellsite equipment may include, but is not limited to, pressure gauges, control panels, switchboards, separators, dehydrators, heater/treaters, flowlines, in-line heaters, storage tanks, or tank batteries.

Off-site: any activity that involves equipment located outside the area of the wellsite.

On-site Processing: also known as “Wellsite Processing,” refers to changes made to the “unprocessed material” that require equipment utilized at the wellsite. Compression, separation, heating/treating, and/or dehydration of oil or gas products are examples of on-site processing.

Off-site Processing: any activity occurring beyond the wellsite that changes the well stream’s physical or chemical characteristics, enhances the marketability of the stream, or enhances the value of the separate components of the stream. Off-site processing includes, but is not limited to fractionation, absorption, flashing, refrigeration, cryogenics, sweetening, dehydration, beneficiation, heating/treating, separating, stabilizing, or compressing.

Oil and Gas Products: any oil or gas material, including but not limited to crude oil, lease condensate, natural gas, entrained natural gas liquids, natural gas liquids, carbon dioxide, and related products.

Operator: any person responsible for the day-to-day operation of a well by reason of contract, lease, or operating agreement. The oil and gas operator is responsible for filing the oil and gas declaration schedule under § 39-7-101, C.R.S, that lists the production and sales for the previous calendar year, and is the sole point of contact for notification, review, audit, protest, abatement, and appeal procedures, § 39-7-110, C.R.S.

Point of Sale: a point where the sale of oil or gas product occurs. The point of sale could be at the physical wellhead, at the meter run, at the Lease Automated Custody Transfer (LACT) unit, at the outlet of the tank battery, or at any place downstream or away from the wellhead.

Point of Valuation: the point, at the wellhead, where the assessor values the well’s unprocessed material that is produced and sold or transported from the wellsite to an off-site point of sale.

Premises: the well location, wellsite, or field area, as referenced in § 39-7-102(1)(b), C.R.S.

Primary Recovery: the recovery of oil, natural gas, or oil and natural gas product by any method (natural flow or artificial lift) that may be employed to produce these products through a single or multiple wellbore. The fluid enters the wellbore by the action of native reservoir energy or gravity. Compare with “secondary recovery.”

Processing: any physical or chemical change to the raw product after it leaves the wellbore, but prior to sale to the first purchaser. Processing can occur both on-site and off-site. Processing includes, but is not limited to, separation of the raw product into its constituent parts, dehydration, measurement, heating/treating, sweetening, compression, and extraction of natural gas liquids.

Secondary Recovery: all methods of oil and natural gas extraction in which energy sources external to the reservoir, other than pumps and pumping units, are used. Examples are: water injection (water-flooding) and gas injection.

Selling Price at the Wellhead: the net taxable revenues realized by the taxpayer for the sale of oil or gas, whether such sale occurs at the physical wellhead, or after wellsite processing, or after transportation that includes gathering, manufacturing, and off-site processing of the product. The net taxable revenues shall be equal to the gross lease revenues, minus deductions for transportation including gathering, manufacturing, and processing costs borne by the taxpayer. Processing costs refer to the costs incurred for both on-site and off-site processing of oil and gas products, § 39-7-101(1)(d), C.R.S.

Take-In-Kind (TIK): an election is made by an interest owner, under a lease or joint operating agreement with notice to the affected parties, to separately market or dispose of crude oil, natural gas, or natural gas products. An interest owner must affirmatively exercise an option under a lease or operating agreement to separately market the interest owner's share of the production to qualify as “take-in-kind.” The definition is taken in part from the Wyoming Department of Revenue, Regular Rules, Chapter 6, § 4b(s), Revised 10/04/1995.

Tertiary Recovery: enhanced methods for the recovery of oil and natural gas that require a means for displacing the oil or natural gas from the reservoir rock, or modifying the properties of the fluids in the reservoir and/or the reservoir rock, to cause movement of the oil or natural gas in an efficient manner and to provide the energy and drive mechanism to force the flow to a production well. Compare with “primary recovery” and “secondary recovery.” Examples are thermal displacement, chemical displacement, and miscible drive displacement.

Transportation: the costs incurred for any movement of a product beyond the gathering system, or beyond the wellsite if no gathering system exists, by truck, rail, or pipeline. For the purpose of the valuation procedures, "Transportation" also includes the term "Gathering."

Wellhead: the point at the surface of the wellbore where there are connections to the casinghead/tubinghead, such as control valves, pressure gauges, testing equipment, and/or flowlines. The end of the casinghead/tubinghead is the point where the “unprocessed material” (referred to in § 3(1)(b), article X, Colorado Constitution) comes out of the wellbore and is the “point of valuation” for oil and gas products. The actual wellhead is seldom used by the oil and gas industry as a “point of sale” for contract purposes.

Wellsite: referred to as the “location” of the wellbore, the wellsite provides a sufficient area of land to contain the wellhead and the equipment necessary for on-site activity, which consists of on-site processing, metering, and storage. Typical wellsite equipment may include: pressure gauges, flowlines, meter run, LACT unit, control panels, switchboards, separators, heater/treaters, dehydrators, storage tanks, tank batteries, and/or other equipment.

Determining Leasehold Value of an Oil or Gas Wellsite

The leasehold value of the wellsite is equivalent to 100% of all the interests in the well including all taxable royalty and working interests. The leasehold value is determined, using the following information:

1. Amount of oil and/or gas product sold or transported from the premises at a downstream point of sale.
2. The value of any product sold or taken-in-kind by an exempt royalty owner as specified in § 39-7-101(1.5), C.R.S.
3. The actual or determined selling price at the physical wellhead of the oil and/or gas product.

The amount of oil and/or gas product sold or transported from the premises, and the value of any product sold or taken-in-kind by an exempt royalty owner (items #1 and #2 above) can be determined from information declared by the taxpayer on the DS 658.

Constitutional and Statutory References

Section 3, article X, Colorado Constitution, states, in part, that oil and gas valuation for assessment is based on the value of the unprocessed material.

Section 3. Uniform taxation - exemptions.

(1)(b) However, the valuation for assessment for producing mines, as defined by law, and lands or leaseholds producing oil or gas, as defined by law, shall be a portion of the actual annual or actual average annual production therefrom, based upon the value of the unprocessed material, according to procedures prescribed by law for different types of minerals. Non-producing unpatented mining claims, which are possessory interests in real property by virtue of leases from the United States of America, shall be exempt from property taxation (emphasis added).

§ 3(1)(b), article X, Colorado Constitution

The selling price of oil and gas sold or transported from the premises is determined at the wellhead, § 39-7-101(1)(d), C.R.S.

Statement of owner or operator.

(1)(d) The selling price at the wellhead. As used in this article, "selling price at the wellhead" means the net taxable revenues realized by the taxpayer for the sale of the oil or gas, whether such sale occurs at the wellhead or after gathering, transportation, manufacturing, and processing of the product. The net taxable revenues shall be equal to the gross lease revenues, minus deductions for gathering, transportation, manufacturing, and processing costs borne by the taxpayer pursuant to guidelines established by the administrator (emphasis added).

§ 39-7-101, C.R.S.

The operator, or owner that files the statement with the assessor, is the sole point of contact for the assessor, § 39-7-110(2), C.R.S.

Oil and gas operator - definition.

(2) Notwithstanding any other provision of law, the partial interests of oil and gas fractional interest owners are not subject to separate valuation by the assessor and shall be represented by the well or unit operator of each wellsite. The well or unit operator is the sole point of contact for all notification, review, audit, protest, abatement, and appeal procedures.

§ 39-7-110, C.R.S.

Interpreting these citations consistently requires that the product sold or transported from the premises be valued under three conditions:

1. The product or material coming out of the wellbore must be valued in its “unprocessed” state.
2. The product’s “selling price at the wellhead” must be determined at the wellhead, whether or not such sale actually occurred at the wellhead, and
3. Partial interests of oil and gas fractional interest owners are represented by the operator and are not subject to separate valuation.

Illustration of Typical Wellheads

To understand what a “wellhead” consists of, please examine the two diagrams in the following illustration.

The diagram on the left is a simple well. It shows that the wellbore consists mostly of a cement sheath; and inside that, the well casing; and inside that, the well tubing. As the casing and tubing approach the top of the wellbore or hole, the ends must have reinforcement due to pressure and the need for stabilization at the top of the well. The reinforced end of the casing is called the “casinghead.” The end of the tubing is called the “tubinghead.” Attached at the ends of the casinghead/tubinghead are a set of valves connected to horizontal flowlines, as shown in the diagram. The casinghead, tubinghead, and attached valves constitute a “wellhead.” The flowlines deliver the oil or gas to other equipment. The configuration is typical for a low-pressure or free-flowing well.

The diagram on the right shows a typical configuration for a high pressure well. The series of valves and gauges attached to the casinghead/tubinghead is known as a “Christmas tree.” Its purpose is to confine and control the flow of fluids or gases from the well. The casinghead/tubinghead and the attached Christmas tree constitute a high-pressure “wellhead.”

The term “unprocessed,” as used in the Colorado Constitution, requires that the product or material receive no processing before valuation. Product flowing through the physical wellhead at the end of the casinghead/tubinghead qualifies as material that has received no processing.

The statute’s phrase “selling price at the wellhead” qualifies the “wellhead” as the point where the “unprocessed material” is valued. Allowable costs or expenses for “processing,” as stated in the statute, include both on-site and off-site processing because such processing occurs beyond the physical wellhead.

Point of Valuation at the Wellhead

For ad valorem purposes, the term “wellhead” is defined as “the point at the surface of the wellbore where there are connections to the casinghead/tubinghead, such as control valves, pressure gauges, testing equipment, and/or flowlines.” In the previous illustration, an arrow indicates the “Point of Valuation” for each wellhead. Direct costs and appropriate Return of Investment (RofI) and Return on Investment (ROI) related to control valves, pressure gauges, testing equipment, and/or flowlines are deductible netback expenses.

Historical Context of Wellhead Pricing and Statutes

Few oil and gas owners or operators actually sell their product at the physical wellhead (point of valuation). The term “selling price at the wellhead,” as traditionally used by the oil and gas industry, has frequently meant the price at the meter run, the price at the LACT unit, or the price at the outlet of the tank battery. The practice dates back to the period prior to the federal deregulation of the oil and gas industry when operators or owners could only sell product to pipeline companies. Current federal regulations permit operators or owners to sell to whomever and wherever they choose. Sales can occur at any designated point “downstream” from the physical wellhead. Regardless of the oil and gas industry’s practice, an ad valorem definition for “wellhead” must meet the criteria established by the Colorado Constitution and the statutes.

When completing the DS 658, it is the responsibility of the owner or operator to declare where the actual “point of sale” of an oil or gas product occurred. When the owner or operator’s gross lease revenues were determined to have occurred anywhere beyond the “point of valuation” at the wellhead, the revenues must be netted back to a wellhead selling price for assessment purposes.

Primary Production Valuation

For leaseholds and lands in primary production, the assessed valuation is eighty-seven and one-half percent (87.5%) of the following:

1. The actual or determined selling price at the physical wellhead of product sold during the previous calendar year
2. The actual or determined selling price at the physical wellhead for oil and gas sold in the same field area for product transported unsold from the premises during the preceding year

Example: Valuation of Leasehold in Primary Production

The subject is an oil well on state land that was producing in the prior year utilizing primary production methods. All products were sold to the first purchaser at the meter run. Costs (including RofI and ROI) related to the equipment used for on-site processing were deducted to arrive at a selling price at the wellhead.

The state land fractional royalty interest is 12.5% of gross production and totals $32,500. Royalty interest percentages can vary depending upon the terms of the lease; dollar amounts should be used. If the dollar amount is deducted it does not affect final value whether the deduction is from the gross or netback amount. The operator of the well filed a properly completed DS 658 for the assessment year.

Step #1 From Section C1 of the completed DS 658, determine the quantity of product (oil and gas) sold during the preceding calendar year.

Step #2 Also from Section C1 determine the point of sale price received for the product during the preceding calendar year.

Step #3 If the point of sale price is on a per-unit basis, multiply the quantity of product from Step #1 times the price from Step #2 to calculate the total value of the product sold.

Step #4 From Section D of the DS 658, determine the amount, in dollars, of royalty interest to be excluded and subtract that amount from the total value of the product sold to get the adjusted gross value.

Step #5 Determine the expenses (either by direct costs or by cost per barrel) that are appropriate to adjust the point of sale price back to the well head. These are known as the netback expenses.

Step #6 Deduct the netback expenses from the adjusted gross value to get the value of the product at the wellhead. This is the netback value.

Step #7 Multiply the netback value by 87.5% (the assessment percentage for primary production) to calculate the assessed value.

Calculation:

Only royalties paid to the United States government, the State of Colorado, counties, cities, towns, municipal corporations, or other governmental organizations within the State of Colorado, including Indian tribes are deducted. Royalties paid to any other person or entity are not deducted.

Secondary Production Valuation

For leaseholds and lands in secondary production, the assessed valuation is seventy-five percent (75%) of the following:

1. The selling price at the physical wellhead of product sold during the previous calendar year
2. The selling price at the physical wellhead for oil and gas sold in the same field area for product transported unsold from the premises during the preceding year

The calculation of the assessed valuation for a leasehold that has secondary or tertiary production for the whole year is the same as for primary production, except that the assessment rate is 75% instead of 87.5%.

An owner or operator, agent, or a person placed in control of the wellsite or lease by the owner or operator, claiming secondary production on the DS 658 must be on record with the Colorado Energy and Carbon Management Commission as approved for secondary production.

Example: Changing from Primary to Secondary or Tertiary Recovery

The producer/operator provided the amounts produced from each recovery method for the previous year. The subject is an oil well that was producing in the year prior to assessment utilizing both primary and secondary (water injection) production methods. All products were sold to the first purchaser at the outlet of the tank battery. Royalty interests have been deducted. Costs (including RofI and ROI) related to the equipment used for on-site processing were deducted to arrive at a selling price at the wellhead. The owner or operator of the well filed a properly completed DS 658.

Step #1: From Sections C1 and C2, determine the amount of product (oil and gas) sold for each recovery method during the preceding calendar year and the average price paid for the product during the preceding calendar year.

Step #2: For each recovery method, multiply the average netback wellhead price paid for the product by the amount of product sold during the previous calendar year to calculate the total value of the product.

Step #3: For each recovery method, multiply the total value of the product by the appropriate assessment rate: 87.5% for primary, 75% for secondary, to calculate the final assessed value.

Calculation:

Previous calendar year primary production 1,500 Bbls
Previous calendar year secondary production 2,500 Bbls
Average netback wellhead price paid per barrel $60.00/Bbl

Valuation of Primary Production

Valuation of Secondary Production

Total Assessed Valuation

Example: Changing from Primary to Secondary or Tertiary Recovery Using the Percentage Allocation Method

The owner or operator of the well does not report the production under each method separately, although the assessor is aware of the change from primary to secondary/tertiary recovery. The assessor uses a percentage allocation method of valuation. The Colorado Energy and Carbon Management Commission (ECMC) has the date of change to another means of production for the wells, as well as the starting date of each secondary/tertiary recovery project.

The steps for the percentage allocation method follow:

1. Calculate the percentage allocation for each recovery method by dividing the total number of days attributable to each recovery method by 365 days.
2. Calculate the total value of production by multiplying the total production by the average netback wellhead price paid for the previous calendar year.
3. Multiply the total value of production by the percentage allocation amount for each recovery method.
4. Multiply the allocated total value of product sold by the appropriate rate – 87.5% for primary, 75% for secondary.
5. Add the value at 87.5% to the value at 75% to arrive at total value for the production.

Assessed valuation attributable to secondary/tertiary recovery is abstracted separately from assessed valuation attributable to primary production.

Methods for Leasehold Valuation

To recognize that each oil and gas owner or operator may have different points of sale, a suggested listing of wellhead pricing procedures was created. Assessors are encouraged to use the following method that is most likely to result in the leasehold’s actual value. The suggested listing is intended to generate equitable leasehold values among all companies and counties.

• Actual Wellhead Price
• Netback of Related and/or Unrelated Party Costs to Value the Leasehold
• Use of Actual Charges to Unrelated Party/Parties as a Comparable Expense Deduction in a Related Party Relationship to Value the Leasehold
• Comparable Netback Sales Price to Value the Leasehold (Only this method should be used for Best Information Available [BIA] valuations.)

The operator is responsible for indicating on the declaration schedule which of the above methods listed is being used. The operator is also responsible for attaching any information (including the Netback Expense Report Form [NERF], if sent by the assessor along with the declaration schedule) to the DS 658 that supports the method used.

Note: If the Netback Expense Report Form is not mailed with the DS 658, a copy may be obtained from the Division’s website. See Addendum 6-J, Oil & Gas Netback IG Corporate Bond Rate, NERF, and NERF Spreadsheet Instructions for more information regarding the NERF.

Under no circumstances will the total deduction for netback of expenses, between the wellhead and the point of sale, exceed ninety-five percent (95%) of the total gross proceeds of product sold less exempt royalties paid. “Carry-forward” or “carry-back” of the unused operating expense, return on investment (ROI), and/or return of investment (RofI) deductions for prior or subsequent years is not allowed.

Netback Expense Report Form and NERF Spreadsheet

To aid the assessor in verifying allowable netback expense deductions, a Netback Expense Report Form (NERF) was developed in cooperation with the Oil and Gas Industry. This form, along with IG Corporate bond rating information, is included as Addendum 6-J, Oil & Gas Netback IG Corporate Bond Rate, NERF, and NERF Spreadsheet Instructions. The frequent use of the Netback Expense Report Form (NERF) resulted in a new electronic reporting tool, the “NERF Spreadsheet.” The NERF Spreadsheet is available to both assessors and taxpayers via the Division’s website. Please see Addendum 6-J, Oil & Gas Netback IG Corporate Bond Rate, NERF, and NERF Spreadsheet Instructions for instructions to access the NERF Spreadsheet on line. Once online, additional information necessary for completion of the spreadsheet is included in the tab labeled “Instructions.” The NERF Spreadsheet will aid the assessor in verifying allowable netback expense deductions and will assist the taxpayer in reporting those deductions.

The use of the NERF by assessors is at the assessor's discretion. The use of the NERF Spreadsheet by taxpayers is at the taxpayer’s discretion. If the assessor chooses to request completion and submission of a NERF, the form may be mailed with the DS 658 or later in the year after the declaration schedules are received. It should be mailed to all oil and gas owners or operators using either the related and/or unrelated party netback expense deduction method or comparable expense deduction method, to determine the wellhead price reported on the declaration schedule. If completion of the NERF is requested, the required filing deadline is 30 days after the date of the request, but no earlier than the statutory April 15th filing deadline for the declaration schedule, § 39-7-101(3)(a), C.R.S. If the NERF is sent along with the declaration schedule, it should be mailed to the oil and gas owner or operator as soon as practicable after January 1 of each year. However, the NERF may be mailed at any time during the current assessment year. In lieu of the NERF, taxpayers may respond by completion and submission of the NERF Spreadsheet electronically.

If an owner or operator, agent, or person placed in control of the wellsite or lease by the owner or operator, willfully fails or refuses to properly complete and submit the NERF, the NERF Spreadsheet, or any other requested supporting documentation within 30 days of the postmark date of the assessor's written request, but not before April 15, the assessor may assess a fine of one hundred dollars ($100) per day, § 39-7-101(3)(a), C.R.S.

The total amount of all fines assessed against an owner or operator, agent, or person placed in control of the wellsite or lease by the owner or operator in any calendar year shall not exceed three thousand dollars ($3,000), regardless of the number of leases or units owned or operated by the owner or operator or the number and length of the willful failures or refusals by the owner or operator.

The assessor may also place a BIA value on the leasehold, § 39-7-104, C.R.S. The Division recommends that the value be based on comparable netback wellhead prices, the average current field price, the average current county price, a statistical average of prices obtained from spreadsheets submitted to the county, or other comparative data.

If the owner or operator, agent, or person placed in control of the wellsite or lease by the owner or operator, properly completes and submits the NERF or NERF Spreadsheet after April 15, for the current assessment year, the assessor may rely on it as part of the "audit and review" procedure.

Oil and Gas Leasehold Valuation Methods

The ideal method for valuation of an oil or gas leasehold is to utilize a sales price that actually occurs at the physical wellhead, if that sales price is the bona fide, arm’s-length, weighted average sales price by product volume for the specific well during the twelve months preceding January 1. If such a price exists, no other leasehold valuation method is necessary. Since few, if any, sales prices are actually established at the physical wellhead, the following valuation methods are applied depending on how the operation is organized.

Netback of Unrelated Party Costs

The netback of unrelated party charges method to value the leasehold is used when:

1. A bona fide arm’s-length sale price is received by the owner or operator at a point downstream from the wellhead, and
2. Unrelated parties are paid for product on-site processing and gathering, and off -site processing, manufacturing, and/or transportation services between the physical wellhead and the actual point of sale.

When using this method, the amounts charged per unit for the transportation, manufacturing, and processing (both on-site and off-site) of the product volume from the physical wellhead to the point of sale by parties unrelated to the owner or operator are deducted from the downstream sales price to determine the wellhead selling price. No costs associated with activities that occur before the wellhead are to be deducted, e.g., down-hole costs, lifting costs, or pumping-related maintenance or operations costs.

Example:

ABC Oil, Inc., owns and operates the well, does its own on-site processing and gathering, pays GHI Processing, Inc. for off-site processing, and pays XYZ Pipeline, Inc., for transporting the product to its point of sale in Chicago.

Since the GHI Processing and XYZ Pipeline companies are not related to ABC Oil, ABC Oil may deduct the full cost of $0.75/Mcf (thousand cubic feet) for transporting the gas to market and the full cost of $0.35/Mcf for off-site processing. ABC Oil may also deduct its own direct costs for on-site processing and gathering, plus Return of Investment (RofI) and Return On Investment (ROI) on its own improvements and equipment that are used for the on-site processing and gathering. The deduction of all the declared costs from its gross lease revenues of $2.00/Mcf results in a netback selling price at the wellhead of $0.80/Mcf. ABC Oil is responsible for submitting supporting documentation for its own deductions, plus proof of receipts from GHI Processing and XYZ Pipeline companies for the netback deductions.

Netback calculations are as follows:

Retail Price/Gross Lease Revenues to ABC Oil: = $2.00/Mcf
Less: Transportation – XYZ Pipeline = - 0.75/Mcf
Adjusted Selling Price: = $1.25/Mcf
Less: Off-site Processing – GHI Processing = - 0.35/Mcf
Adjusted Selling Price: = $0.90/Mcf
Less: Direct Costs – On-site Proc. & Gathering = - 0.05/Mcf
Return On Investment (ROI) – ABC Oil = - 0.02/Mcf
Return of Investment (RofI) – ABC Oil = - 0.03/Mcf
Netback Selling Price at the Wellhead – ABC Oil: = $0.80/Mcf

If a direct exchange of product for downstream product processing services is agreed to as payment for the service, the fair market value of the exchanged product is documented by both the owner or operator and the provider of the service, then reported to the assessor before being allowed as a deductible cost. The owner or operator must include the market value of the exchanged product as part of the leasehold value reported to the assessor.

Netback of Related and Unrelated Party Costs

It is possible that both unrelated party and related party costs of service are used in the netback procedure. The combination may exist when part of the downstream cost of the product is paid to a party unrelated to the owner or operator, e.g., transportation costs from the processing plant to the point of sale at the transmission pipeline. Yet, from the physical wellhead to the point of transportation, the owner or operator, the gatherer, and the processor are all related parties or the same party.

Costs paid to an unrelated party for one or more services, e.g., wellsite processing, gathering, off-site processing or manufacturing, and/or transportation, are generally allowable in determining the netback wellhead price. Costs paid to related parties are deductible in accordance with the procedure in the Netback of Related Party Costs to Value the Leasehold section of these procedures.

Example:

In the following illustration, both related and unrelated parties are involved from the physical wellhead to the point of sale in Chicago. ABC Oil, Inc., owns ABC Processing, Inc., a related party. ABC Oil does not own the XYZ Pipeline company, which is an unrelated party. ABC Oil may deduct the full cost of XYZ Pipeline’s charge for transporting the gas from the processing plant to the point of sale in Chicago.

ABC Oil may deduct only ABC Processing’s direct costs, plus the ROI and RofI on ABC Processing’s off-site improvements and equipment. ABC Oil, Inc., may also deduct its own direct costs, plus ROI and RofI on its own on-site improvements and equipment to arrive at a netback selling price of $0.80/Mcf at the wellhead. ABC Oil is responsible for submitting proof of receipts from XYZ Pipeline and supporting documentation from ABC Oil and ABC Processing companies for the allowable deductions.

Netback calculations are:

Retail Price/Gross Lease Revenues to ABC Oil: = $2.00/Mcf
Less: Transportation – XYZ Pipeline = - 0.75/Mcf
Adjusted Selling Price: = $1.25/Mcf
Less: Direct Costs – Off-site ABC Processing = - 0.20/Mcf
ROI – ABC Processing = - 0.07/Mcf
RofI – ABC Processing = - 0.08/Mcf
Adjusted Selling Price: = $0.90/Mcf
Less: Direct Costs – On-site Proc. & Gathering = - 0.05/Mcf
ROI – ABC Oil = - 0.02/Mcf
RofI – ABC Oil = - 0.03/Mcf
Netback Selling Price at the Wellhead – ABC Oil: = $0.80/Mcf

Netback of Related Party Costs

The netback of related party costs method to value the leasehold is used when:

1. There is no agreement between the owner or operator and any unrelated party responsible for wellsite processing, gathering, off-site processing, and/or transportation of the product to the point of sale, and
2. There is a bona fide arm’s-length selling price received by the owner or operator at a point downstream from the physical wellhead, either by an actual sale of the product at the downstream point or by reference to other criteria, e.g., prices paid for a similar product at that point where a product is "taken-in-kind" and sold elsewhere by the owner or operator, and
3. The same party owns, or related parties are paid for, on-site processing, product gathering, off-site processing, and/or transportation services between the actual wellhead and the first point of sale.

Example:

ABC Oil, Inc. owns ABC Processing, Inc. and ABC Pipeline, Inc. They are all related parties.

ABC Oil may deduct the allowable direct costs incurred by all three companies, plus ROI and RofI on the improvements and equipment owned by all three companies. The allowable direct costs plus ROI and RofI are deducted from the gross lease revenues of $2.00/Mcf to determine a netback selling price of $0.80/Mcf at the wellhead. ABC Oil is responsible for submitting supporting documentation from all three companies for the deductions used to arrive at a selling price at the wellhead.

Netback calculations are:
Retail Price/Gross Lease Revenues to ABC Oil: = $2.00/Mcf
Less: Direct Costs for Transportation = - 0.45/Mcf
ROI – ABC Pipeline = - 0.15/Mcf
RofI – ABC Pipeline = - 0.15/Mcf
Adjusted Selling Price: = $1.25/Mcf
Less: Direct Costs – Off-site Processing = - 0.20/Mcf
ROI – ABC Processing = - 0.07/Mcf
RofI – ABC Processing = - 0.08/Mcf
Adjusted Selling Price: = $0.90/Mcf
Less: Direct Costs – On-site Proc. & Gathering = - 0.05/Mcf
ROI – ABC Oil = - 0.02/Mcf
RofI – ABC Oil = - 0.03/Mcf
Netback Selling Price at the Wellhead – ABC Oil: = $0.80/Mcf

Use of Unrelated Party Charges as Comparables

This method is used when:

1. The same party owns, or is related to the owner of, the gathering system and/or the gas processing plant, and
2. Comparable gas produced by an unrelated party is being sold to the owner of the gas plant or is processed at the plant at a specified arm’s-length unit charge.

Example:

Under the methodology, the gas owned by an unrelated party or parties is gathered and/or processed for a fee. The taxpayer may claim, as a “proxy deduction” in the netback value calculation, the weighted-average of the fees paid by the unrelated party or parties for gathering and/or processing.

ABC Oil, Inc. owns ABC Processing, Inc. Though ABC Processing gathers and processes gas off-site for its related party, ABC Oil, it also gathers and processes gas for three unrelated companies: Bent Oil, Flame Gas, and Geyser Oil. The weighted-average for charges to the three companies is $0.35/Mcf. ABC Oil may use the weighted-average as a “proxy” expense for its cost of off-site gathering and processing through ABC Processing.

In the previous illustration, ABC Oil’s other deductions for related party costs for on-site processing and/or gathering are still allowable since the deductions are not reflected in the weighted-average “proxy” cost established from the unrelated parties. If ABC Oil had sold its gas for $1.25/Mcf to a pipeline company in an arm’s length transaction, the netback calculations would be as follows:

Selling Price to Pipeline Company: = $1.25/Mcf
Less: Average-Weighted “Proxy” Cost = - 0.35/Mcf
Adjusted Selling Price: = $0.90/Mcf
Less: Direct Costs – On-site Proc. & Gathering = - 0.05/Mcf
ROI – ABC Oil = - 0.02/Mcf
RofI – ABC Oil = - 0.03/Mcf
Netback Selling Price at the Wellhead – ABC Oil: = $0.80/Mcf

Since a weighted-average “proxy” cost was used, ABC Oil may not deduct RofI and ROI on the “proxy” cost, even though they are directly related to the ABC Processing company for which the “proxy” cost was developed. RofI and ROI were already included in the unrelated costs used to prepare the weighted-average “proxy” cost.

Instead of a weighted-average “proxy” cost, a taxpayer may also use the price of gas sold to its related gathering or processing company by unrelated parties as a “proxy value” for the gas owned by the taxpayer.

No costs associated with activities that occur before the physical wellhead are to be deducted: e.g., down-hole costs, lifting costs, or maintenance or operations costs related to the pumping unit.

When using weighted-average costs of service to unrelated parties as a deduction for related parties, the quality of the product and the terms and conditions under which the product is being processed and/or transported are considered. Both the unrelated and related parties' product must be comparable in order to properly determine the typical costs of service used.

All costs, for both unrelated and related party cost of services, are documented by the taxpayer and are subject to review and verification by the assessor in accordance with the review and audit procedures in this chapter. If the taxpayer fails to file the required netback expense report form (NERF), or the optional NERF Spreadsheet, if requested by the assessor, or any other documentation requested by the assessor, the assessor has the option to assign a Best Information Available (BIA) wellhead value.

Comparable Netback Sales Price (BIA Valuation)

The comparable netback sales price is defined as the bona-fide arm’s-length, weighted-average, sales price determined from the netted back selling prices, by product volume, of comparable oil and/or gas products sold at other oil and gas wellsites during the preceding year. Use of the comparable netback sales price method to value the leasehold takes into consideration the quality of the product and the terms and conditions under which the product is sold.

This method is used only for Best Information Available (BIA) valuations. The assessor may establish a BIA valuation when the following situations occur:

1. The taxpayer fails to file a completed declaration schedule and/or a completed Netback Expense Report Form (NERF) if requested by the assessor, or
2. The netback expense information provided on the form is inconsistent or incomplete with regard to the actual downstream sales price or expenses required to gather, process, manufacture, or transport the product from the wellhead to the point of sale.

If questions arise regarding downstream sales prices and netback deductions, assessors can utilize the review and audit procedures listed in Review and Audit of Oil and Gas Declaration Information, located later in these procedures, to resolve any problems. No costs associated with activities occurring before the physical wellhead are to be deducted, e.g., down-hole costs, lifting costs, or maintenance and/or operations costs related to the pumping unit.

All information provided to the assessor is confidential, § 39-7-101(4), C.R.S.

Netback Calculation Definitions

Per agreement with assessors and industry, the following definitions only pertain to the netback methods to value the leasehold interest. The definitions are to be adhered to by both the assessor and the declarer when determining leasehold value net of unrelated or related party costs. In every case, the declarer should indicate the leasehold valuation method used on each returned declaration schedule.

Plant or facility depreciation or recapture: the annual expense associated with the amortization of the capitalized cost of a plant or facility, calculated based on a share of gross revenue attributable to a particular product on a units-of-production or straight-line basis and used by the taxpayer for financial statement purposes, in accordance with generally accepted accounting principles.

Related parties: the individuals who are connected by blood or marriage; or partnerships; or businesses that are subsidiaries of the same parent company or are associated by one company controlling or holding ownership of the other company's stock or debt.

Return of Investment (RofI): the owner’s recovery (recapture) of capital invested in equipment and improvements at the wellsite. The return comes through the gross lease revenues from the well’s production that is sold or transported from the premises.

Return on Investment (ROI): the additional amount received by the owner as compensation for the use of the owner’s invested capital until it is recovered (recaptured). The rate of return on invested capital is analogous to the interest rate on a bond investment or certificate of deposit. The return also comes through the gross lease revenues from the well’s production that is sold or transported from the premises

Netback Deductions Involving Related Parties

Related parties may take specific deductions from gross lease revenues to determine the net selling price at the wellhead. Deductions may be taken for allowable direct operating costs or expenses, for Return On Investment (ROI), and for Return of Investment (RofI). Netback expenses may be claimed by the taxpayer or by parties directly related to the taxpayer. To ensure that a taxpayer’s netback deductions are supportable, the deductions must meet the following criteria.

Deduction of Direct Operating Costs

Direct operating costs are defined as costs incurred during the previous calendar year that are directly associated with on-site processing and gathering, and off-site processing, manufacturing, and transportation of the product from the physical wellhead to the point of sale. Direct operating costs are deductible from the downstream gross lease revenues to determine the netback selling price at the wellhead. No costs associated with activities that occur before the physical wellhead are to be deducted: e.g., down-hole costs, lifting costs, or maintenance or operations costs related to the pumping unit.

Allowable Operating Cost Deductions

Operating costs directly related to the operation and maintenance of the equipment and facility that are typically allowed are:

• Salaries, wages, and benefits paid by the entity claiming the deductions to employees and supervisors directly involved with the wellsite activity or related off-site activity.
• Fuel (including electricity or natural gas) and utility costs.
• Materials and supplies including chemicals and lubricants.
• Non-capitalized repairs, including labor and materials related to gathering, on-site and off-site processing, or transportation of the product from the wellhead. Deductions for repairs and/or maintenance of the pumping unit or down-hole equipment are not allowed.
• Field labor costs, including third party charges that are related to on-site and off-site processing, and transportation of the product from the wellhead to the point of sale.
• Costs related to the repairs and maintenance of the above-ground wellsite equipment.
• Costs incurred for the sale of the product at the point of sale.
• Taxes on real property improvements and personal property attributable to the facility.
• Cost of preparing an environmental impact statement.
• Annualized insurance expense, including workman’s compensation insurance, general or public liability insurance, and automobile public liability insurance for vehicles used at the site.
• Payroll taxes.
• Unrelated party rental, leasing, or contract service costs for operation of the equipment and facility.
• Allocated direct general and administrative overhead costs, e.g., headquarters personnel, telephone service, payroll taxes, employee benefits, vehicle expenses, office supplies, etc., that represent typical expenditures allocable to the operation and maintenance of the equipment and facilities, both on-site and off-site.

In some instances, actual costs for some or all of the above items may not be available by well. When costs are not available by well, both the assessor and taxpayer can establish and agree to a reasonable basis for an allocation of costs between deductible and non-deductible categories or processes. Once the allocation methodology is established, it cannot be changed without agreement of the county assessor. Replacement costs or “proxy” costs cannot be used in lieu of historical costs. The owner or operator must provide actual historical costs.

The above list is not all-inclusive. Additional costs necessary for the gathering, on-site and offsite processing, and transportation or movement of the product from the actual wellhead to the point of sale may be allowed. A good “rule of thumb” is that the costs associated with a process that adds value to the oil and gas product prior to sale are allowable.

Non-Allowable Operating Cost Deductions

Direct operating costs that are not allowable are:

• Down-hole production and operating costs incurred to extract or move the product from the reservoir to the wellhead. Included in the category are costs for gas, water, and/or CO2 injection done as part of a secondary recovery process.
• Royalty payments (royalty payments to property tax exempt entities are excluded later to determine the taxable leasehold value).
• Costs related to the repairs and/or maintenance of the pumping unit, tubing, casing, liners, or down-hole equipment, parts or supplies.
• Drilling or well-completion costs, including expenses for cementing and/or perforating of the wellbore.
• Legal costs, title opinions, and any other pre-drilling or pre-production costs.
• Work-over, “well-pulling”, or well re-completion costs.
• Federal and state severance, income, or other taxes (except payroll taxes and improvement and equipment property taxes).
• Theoretical or actual line losses or “shrinkage.”
• Property taxes on oil and gas leaseholds and lands.
• Oil and gas depletion allowances.
• Any other cost that is not considered a direct operating cost of gathering, on-site or offsite processing, manufacturing, and transportation, including construction period interest.
• Capitalized interest charges expended during development and/or construction, either as a separate line item or included as a component in the undepreciated investment balance.

Deductions - Return On Investment (ROI) and Return of Investment (RofI)

Related party and vertically integrated (combined production, on-site and off-site processing, and/or transportation company) operators are entitled to deduct an amount for ROI and an amount for RofI on their capital assets. Capital assets are depreciable fixed assets necessary for on-site processing and gathering, and off-site processing, manufacturing and transportation of the oil and gas product to the point of sale. Fixed asset costs for real property include costs of construction of an improvement or structure, but do not include costs of acquiring land upon which the structure is built. Fixed asset costs for personal property include the cost of acquisition, cost of delivery, sales tax, and installation of the personal property item.

Since ROI represents the additional amount received by the owner as compensation for the use of the owner’s invested capital until it is recovered (recaptured), the return comes through the gross lease revenues from the well’s production that is sold or transported from the premises. ROI is analogous to the interest rate on a bond investment or certificate of deposit.

RofI, on the other hand, represents the owner’s recovery (recapture) of capital invested in equipment and improvements at the wellsite. The return also comes through the gross lease revenues from the well’s production that is sold or transported from the premises.

Determining ROI and RofI require different bases for their calculations:

1. ROI requires an average of the remaining undepreciated investment balance of includable assets on January 1 of the prior calendar year and the remaining depreciated investment balance of includable assets as of December 31 of the prior year.
2. RofI requires only the remaining, undepreciated investment balance of includable assets on January 1 of the prior year as the base.

RofI and ROI are not allowed on acquisition and installation of pumping units, casing and tubing, down-hole equipment, and any other machinery and equipment used to extract, produce or lift the product from the reserve to the wellhead.

Included Assets In the Physical Asset List

Assets that can be included:

• Buildings, shops, laboratories, sidewalks and fences, roads and other structures and improvements that are directly related to the wellsite processing, gathering, off-site processing, and/or transportation of the product from the actual wellhead to the point of sale, and that are located either on the lease or within the production field area.
• Machinery and equipment directly used for wellsite processing, gathering, off-site processing or manufacturing, and transportation.
• Environmental equipment that is an integral part of the facility.
• Piping and flow lines including meters, valves, and fittings.
• Water wells and supply systems, heat, sewage, and other utility systems located at the facility site.

The above list is not all-inclusive. Any capital assets directly involved in the on-site processing and gathering, or off-site processing or manufacturing, and transportation are included.

Excluded Assets from the Physical Asset List

Assets that must be excluded:

• Pumping unit, casing, tubing, liners, and down-hole equipment.
• Non-depreciable property such as land and pipeline rights-of-way.
• Capitalized improvements or assets that are not an integral part of the wellsite processing and gathering, or off-site processing or manufacturing, and/or transporting operation.
• Capitalized interest charges expended during development and/or construction, either as a separate line item or included as a component in the undepreciated investment balance.

Determining the Amount of ROI Deduction

The actual amount allowed for deduction will be the lesser of:

1. The actual ROI obtained by the related party in providing the wellsite processing and gathering, and off-site processing or manufacturing, and/or transportation service, if the related party lists on its books and records a charge for any of these services from which an actual ROI can be determined, or
2. A calculated ROI amount based on the average undepreciated investment balance for the calendar year prior to the year of assessment of the improvements and personal property multiplied by the average industrial bond yield rate for the calendar year prior to the year of assessment as published by the Division.

The industrial bond rate is to be used whenever it is less than the actual rate of ROI. For oil and gas companies that cannot, for accounting purposes, calculate an actual ROI, the published ROI is allowed for determining the deduction for return on investment. Please refer to Addendum 6-J, Oil & Gas Netback IG Corporate Bond Rate, NERF, and NERF Spreadsheet Instructions, for the current published Netback IG Corporate Bond Rate.

Example:

The Derrick Oil & Gas Company declared the following information using the Netback Expense Report Form (NERF):

*From Addendum 6-J.

Determining the Amount of RofI Deduction

The actual amount allowed for deduction may be calculated either by:

1. Dividing the remaining undepreciated investment balance of the improvements and equipment by the asset life of the improvement or equipment item using a non-accelerated, straight-line depreciation schedule, or
2. Using a Units-of-Production (UOP) method.

Example: Investment balance divided by asset life method (a.)

The Derrick Oil & Gas Company declared the following information, using the DS 658 and the Netback Expense Report Form (NERF):

Example: Using the Units-of-Production (UOP) method (b)

The Derrick Oil & Gas Company declared the following information, using the DS 658 and the Netback Expense Report Form (NERF), and reserve estimates from its IRS return:

If the UOP method is selected, the taxpayer provides the assessor with adequate documentation, including reserve estimate information furnished to the IRS that indicates the probable recoverable reserve amount existing under the leasehold.

Once a depreciation method has been selected, it cannot be changed except by approval of the county assessor.

All costs, for both unrelated and related party services, must be documented by the taxpayer and are subject to review and verification by the assessor in accordance with the review and audit procedures in this chapter. If the taxpayer fails to file the NERF or any other documentation as required by the assessor, the assessor has the option to assign a BIA wellhead value.

Assessment of Natural Gas Liquids

Natural gas liquids (NGLs) produced from oil and gas leaseholds and lands are organic hydrocarbon products suspended within a natural gas stream. The unprocessed natural gas stream containing the NGLs is termed “wet gas.” The NGLs are termed “entrained liquids,” and include ethane, propane, and butane among other organic compounds that are produced from the oil and gas wellbore. After the NGLs are extracted from the natural gas stream, the remaining product consists primarily of methane and other combustible gases termed “residue,” “residue gas,” or “dry gas.”

After NGLs are removed, the residue gas is compressed and transported, generally through pipelines, to end users. NGLs are shipped, usually by truck or pipeline, from the gas processing plant to a facility where they are separated into their constituent parts by a process known as fractionation.

Accounting for the value of NGLs in the oil and gas leaseholds and land valuation process is done differently depending on the point of sale of the natural gas stream.

1. If the point of sale and transfer of the “wet” natural gas product is done at the wellhead, or at any point prior to separation and/or NGL extraction, the value of any entrained NGLs is presumed to be included in the price-per-Mcf paid for the “wet” gas. It is not possible to value the NGLs separately.
2. If the point of sale and transfer of the NGLs is after separation and/or extraction, both the residue gas and NGLs are separately valued. However, the values of both the residue and the NGLs must be “netted back” to what the product would have sold for at the wellhead.

The netback adjustments must account for all on-site and off-site processing and transportation costs that were expended to make the product marketable and transport it to the point of sale. For additional information on the netback process refer to Description of Oil and Gas Leasehold Valuation Methods earlier in this chapter.

There are various ways of accounting for NGL processing. One way is for the gas processor to retain a portion of the NGL gross lease revenues as the fee for extraction of the NGLs from the gas stream. In years when the price of crude oil and NGLs is high, the proceeds retained by the natural gas process may also pay for processing the residue gas as well.

Example:

Horizon Oil Inc. operates a 40-acre lease that produces unprocessed gas with entrained natural gas liquids (NGLs) from a single well. Horizon meters the unprocessed gas at the wellsite and ships it through its own gathering system to a plant owned by Aurora Gas Processing.

At the plant, the gas is processed, NGLs are extracted, and the residue gas is compressed for shipment into the Sunset Gas Transmission Pipeline. The previous year’s production from the well was 60,000 Mcf of gas with 6,000 gallons of associated NGLs. The average price paid for the NGLs during the previous year was $1.00/gallon. Fifty-eight thousand (58,000) Mcf of residue gas was sold at the inlet to the gas transmission pipeline for $4.50 per Mcf. According to the contract between Horizon and Aurora, Aurora agrees to separate the unprocessed gas into pipeline quality residue gas and extract the associated marketable NGLs. For processing and compressing the gas for pipeline shipment, Aurora keeps 50% of the NGL gross lease revenues.

Costs documented by Horizon:

Gathering: $27,000 $.45 per Mcf

The above costs were claimed in total when the netback valuation of the residue gas was calculated. Based on the published oil and gas netback procedures, the netback wellhead valuation of the residue dry gas and the NGLs is shown below:

Dry Residue Gas

NGLs

^A Since the processing cost includes the cost of processing the residue gas as well as the NGLs, no additional deduction for processing is allowed when determining the netback value of the residue gas.
^B Since gathering costs were already claimed by the operator in valuing the residue gas at the wellhead, it would be improper to allow an additional deduction for the NGL netback valuation.

It is important that separate netback deduction calculations be completed for the residue gas and for the extracted NGLs to avoid deducting the netback processing or transportation costs twice. If a well producing natural gas has NGLs separately valued from the residue gas, information is required showing how deductible costs are allocated for both transportation and processing of the residue gas and transportation and processing of the NGLs.

Calculations for ROI and RofI have not been shown in the NGL example, but are deductible when determining the netback selling price at the wellhead. Please see the calculation examples under Deductions for Calculating Return On Investment (ROI) and Return of Investment (RofI).

Landfill Methane Extraction Production

Gas extraction operations located on sanitary landfills, or lands from which gas from decomposing material is extracted for sale, are assessed at 75% of the value of the gas sold or transported from these operations. Taxpayers are required to file a DS 658 with the county assessor.

Valuation procedures for landfill methane extraction operations are the same as for other secondary, tertiary, or recycling/recovery operations.

Shut-In and Capped Wells

Shut-in and capped wells are wells that are still capable of production, but due to economics or other circumstances, were temporarily taken out of production for the entire previous calendar year. Oil and/or gas resources may remain in the ground.

Wells that were shut-in and capped as of the assessment date, but from which oil and/or gas was sold or transported during the previous calendar year, should be valued based upon that production volume. Wells that were shut-in and capped for a period of time in excess of the previous calendar year are not valued, except for the valuation of personal property on the site. Personal property includes a wellhead and equipment stored on the site.

If the oil and gas mineral interest is severed from the surface ownership and there was no production from the shut-in and capped well(s) during the previous calendar year, the interests are valued as nonproducing oil and gas mineral interests, § 39-7-109, C.R.S. Please refer to the Valuation Procedures for Nonproducing Severed Mineral Interests in this chapter.

If the oil and gas mineral interest is not severed from the surface ownership and there was no production from the shut-in and capped well(s) during the previous calendar year, no value is assigned. Mineral rights are not separately valued from surface real estate in Colorado unless the ownership of those mineral rights is severed from the surface ownership.

Plugged and Abandoned Wells

Plugged and abandoned wells are wells with no foreseeable future production. Any remaining reserves have no current, profitable method of recovery.

Wells that were plugged and abandoned as of the assessment date, but from which oil and/or gas was sold or transported during the previous calendar year, are valued on the actual production volume for the previous calendar year. For plugged and abandoned wells without any production during the prior calendar year, only the value of the equipment stored at the wellsite should be listed and valued if it was not held for sale. Any severed mineral interest in the lands will become taxable once production has ceased permanently. Please see Valuation Procedures for Nonproducing Severed Mineral Interests in this chapter.

Orphaned Wells

Orphan wells are those wells in which no operator or owner, defined in § 39-7-110, C.R.S., can be found or contacted, or is unwilling or unable to plug and abandon the well. When the operator or owner of the property cannot be determined after due diligence by the assessor, the property may be listed as “owner unknown” pursuant to § 39-5-102(2), C.R.S.

Wells that are orphaned as of the assessment date, but from which oil and/or gas was sold or transported during the previous calendar year, are valued based on the actual production volume for the previous calendar year. For orphaned wells with or without any production during the prior year, equipment at the wellsite should be listed and valued using the appropriate BEL tables and equipment lists found in ARL Volume 5, Chapter 6, Oil and Gas Equipment Valuation. If the owner or operator cannot be found or contacted, and no statement is filed as required by the provisions of section § 39-7-101, C.R.S., then the assessor should list and value the property on the basis of best information available and obtainable pursuant to § 39-7-104, C.R.S.

More information about orphan wells is available at The Energy & Carbon Management Commission (ECMC) Orphaned Well Program.

Gas Flared, Vented, or Re-Injected on the Lease

Gas that is flared, vented, or re-injected on the lease to maintain field pressure is not valued. The statutes only provide for assessing the product that is sold or transported from the premises, § 39-7-102, C.R.S.

Other Issues

Confidentiality Requirements

All information or documentation provided to the assessor, the Property Tax Administrator, the annual study contractor hired under § 39-1-104(16), C.R.S., the executive director of the department of revenue, and their employees, will be considered private and confidential, § 39- 7-101(4), C.R.S. Such information or documentation includes declaration schedules, accompanying exhibits, the Netback Expense Report Form (NERF), electronic or printed spreadsheet files, any documentation supporting the NERF, and any other information or documentation supplied as part of the audit or review process.

Best Information Available Assessments

If the declaration schedule fails to provide sufficient information to determine or justify the reported value, the assessor utilizes; comparable netback wellhead prices, the average current field price, the average current county price, statistical-average prices from spreadsheets, or other comparative data to value the product. Please see Review and Audit of Oil and Gas Declaration Information in this chapter.

It is strongly advised that the assessor statistically analyze the reported prices-per-unit from all declaration schedules. Please see Statistical Review of Wellhead Prices, later in this chapter, for additional information.

Taxpayer Notification

The well or unit operator is the sole point of contact for all notification, review, audit, protest, abatement, and appeal procedures, § 39-7-110(2), C.R.S. Whenever leasehold values determined by the assessor differ from the values reported on a declaration schedule, the assessor must notify the operator or owner/operator using the “Note” field on the Notice of Valuation (NOV).

Excludable Royalties

Royalties that are delivered as cash or as product to governmental entities are excluded from the gross revenues before calculating actual value at the wellhead. The exclusion is the actual royalty amount paid, not necessarily the royalty declared, whether shown as a fraction, percentage, or flat amount. The actual royalty paid is subtracted from the total value of the product sold or transported. Governmental entities include any interests owned by: the United States government, State of Colorado, counties, cities, towns, municipal corporations, or any other governmental entities within the State of Colorado, including Indian tribes.

Oil/Gas Leaseholds, Lands Sold Previous Calendar Year

When producing oil and gas leaseholds and lands are sold or conveyed to a new owner during the year, a declaration is filed by the new owner of the property for the assessment year following the year in which the oil and gas property was sold or conveyed. All oil and gas production and sales information, including the amount of oil and gas produced, sold, flared/vented, and used on lease for the entire preceding calendar year, is reported to the assessor, § 39-7-101(1), C.R.S.

The requirement applies to oil and gas sold, or transported unsold, from the premises during the preceding calendar year by both the previous owner and the current owner. If the new owner is unable to get an accounting of oil and gas production from the prior owner, an alternative source of information is the Colorado Energy and Carbon Management Commission (ECMC) Form 7 submittals made by the prior owner for the months in question. The ECMC may be contacted at (303) 894-2100, or through its website: https://ecmc.state.co.us/#/home.

New owners of oil and gas leaseholds and lands are responsible for the entire property tax lien that attaches on the January 1 assessment date following the transfer of the property. Any liability for property taxes arising from oil and gas sales occurring prior to the date of conveyance of the leasehold should have been settled at the time of closing, §§ 39-1-107 and 39-7-108, C.R.S.

Level of Value for Producing Oil and Gas

All producing oil and gas leaseholds and lands are valued at current value using the previous year's production information, §§ 39-1-103(2) and 104(12)(b), and 39-7-101 and 102, C.R.S.

Review and Audit of Oil and Gas Declaration

The assessor may request information from a taxpayer relating to the actual value of any property located within the county, § 39-5-115(1), C.R.S. Assessors may conduct reviews or audits of taxpayer oil and gas declarations and may request supporting documentation associated with specific wells owned or operated by the taxpayer, § 39-7-101(3) and 105, C.R.S.

A review is defined as an analysis of oil and gas production and sales volumes, expressed in Bbl (barrels) or Mcf (thousand cubic feet), reported on the DS 658 Oil and Gas Real and Personal Property Declaration Schedule filed by the taxpayer, as compared to reports Form 7 and Form 8 filed with the Colorado Energy and Carbon Management Commission (ECMC). Also included under the review process is an analysis of requested supplemental information under § 39-7-101(3), C.R.S., which may include the Netback Expense Report Form (NERF).

• The ECMC Form 7 is filed monthly by the lease operator and contains detailed production volume information reported by the operator for all interest owners of the well. Form 7 also is the method by which the ECMC maintains its production database. Form 7 includes unsold production stored at the lease site, which is not assessable until it is sold or transported from the lease site unsold. Form 7 is public information.
• The ECMC Form 8 is filed quarterly, usually by the first purchaser or the operator. Form 8 contains both volume and price information for the operator, but sales price information is not available by lease or by well. ECMC Form 8 submissions are by operator instead of by lease. Only a composite sales price by operator is available for comparison. Therefore, Form 8 information cannot be relied upon for calculation of average field price. Form 8 is the method by which the ECMC collects its conservation levy. Form 8 is public information.

An audit is defined as an examination and analysis of taxpayer's records, including source documents, regarding production and sale volumes, sales price per Bbl. or Mcf., or any other information reported by the owner or operator.

Purpose and Scope

Section 39-2-109(1)(k), C.R.S., requires the Administrator to develop guidelines for the review and audit of oil and gas leaseholds and lands.

The guidelines provide procedures and instructions for the review or audit of information filed with the county assessor, pursuant to § 39-7-101, C.R.S.

All county assessors, county treasurers, and their agents must utilize the procedures and instructions, § 39-2-109(1)(k) C.R.S. For the purpose of the procedures, a county’s "agent" is defined as "any person or business that contracts with the county to perform reviews or audits of oil and gas production records to determine if the amounts declared by taxpayer(s) to the county are correct."

Oil and Gas General "Review" Procedures

Counties are permitted to establish reasonable "review" procedures that fairly and accurately determine if any discrepancy exists between the taxpayer's declared oil and gas production and sales volumes and the amounts indicated by other information sources. The following must be included in the county's review program for oil and gas taxpayers:

1. All of a taxpayer's wells within the same field or unitized operation shall be included in the review process. The following reports are sources that can be used for review purposes:

   1. Colorado Energy and Carbon Management Commission (ECMC) online production reports derived from Forms 7 and 8. As of July 1, 2001, data taken from Form 8 reports submitted to the ECMC contain only composite sales information by operator. Information is not available by well. The actual Form 7 and Form 8 reports can only be viewed or reviewed by going in person to the ECMC record-keeping facility at:
      
      Colorado Energy and Carbon Management Commission
      The Chancery Building
      1120 Lincoln Street, Suite 801
      Denver, CO 80203
      Phone: 303-894-2100

      Various kinds of valuable information can be obtained online through the ECMC website. Please see Addendum 6-H, Instructions for Accessing the ECMC Website, at the end of this chapter.

   If supporting documentation is requested by the assessor, including a completed NERF requested under § 39-7-101(3), C.R.S., the taxpayer has the option of submitting either the NERF or an electronic NERF Spreadsheet in addition to any other requested materials.

2. The county assessor must provide a letter to the taxpayer, by certified mail, indicating that a "review" of the taxpayer's oil and gas declaration was conducted. The letter must include:

   1. A listing of the assessment years reviewed.
   2. A listing of the wells, leases, units, or fields reviewed.
   3. A listing of the sources used to determine any apparent volume discrepancies.
   4. An explanation of any discrepancies between the taxpayer's declaration and the sources utilized by the county. Include in the explanation a listing of the taxpayer's declared volumes and the amounts indicated on the county's source reports.
      
      In computing the value of the indicated under-or-over-reporting of volume, the county utilizes the taxpayer's average price as declared on the taxpayer declaration for the specific year under review.
       
   5. Any requests for additional information regarding the taxpayer reporting discrepancy.
   6. A listing of the taxpayer's rights in the "review" process.

   Please refer to the Oil and Gas Taxpayer "Review" Rights section of these guidelines for further information.

3. If a change in valuation is determined, the county uses the Division-approved Special Notice of Valuation, Special Protest Form, and Special Notice of Determination forms listed in ARL Volume 2, Administrative and Assessment Procedures, Chapter 9, Form Standards. If the county wishes to develop its own form(s), the Division of Property Taxation must approve each form prior to use.
   
   A Special Notice of Valuation is mailed after the taxpayer response period expires. The assessor may grant additional response time at the request of the taxpayer. If the taxpayer requests additional time, and if the assessor grants it, the assessor must wait until the complete response period, as granted, expires.
    
4. If the taxpayer does not provide the requested information, or refuses to make the information available, the assessor may:
   1. File in District Court under § 39-5-119, C.R.S., for a court order compelling the taxpayer to immediately cooperate with the assessor; or
   2. Issue a Best Information Available (BIA) assessment.

Oil and Gas Taxpayer "Review" Rights

The following rights are provided to all taxpayers subject to a county oil and gas "review:"

1. At the request of the taxpayer, the county schedules a meeting to discuss the discrepancies and to receive any further information from the taxpayer.
2. At the request of the taxpayer, the assessor provides the taxpayer copies of all information used to determine the discrepancy.
3. Taxpayers have at least 30 days to respond to the "review" notification letter and to provide additional information to the county regarding the listed discrepancies. The assessor may grant additional time at the request of the taxpayer.
4. Taxpayers have 30 days to protest the value indicated on the Special Notice of Value. The county must consider all information supplied by the taxpayer in protest.
5. If a taxpayer files a protest, the county issues a Special Notice of Determination. Language regarding a taxpayer’s appeal rights for filing an abatement petition is included in the Special Notice of Determination.

Statistical Review of Wellhead Prices

It is strongly advised that the assessor choose a convenient time within the assessment year to statistically analyze the reported prices-per-unit from all declaration schedules. Information is analyzed by well and stratified by field.

At a minimum, the data is arrayed from low to high. Measures of central tendency (median and mean) are established for independent operators, producers, and other royalty interest owners for all schedules. These statistical analyses aid the assessor in determining which declaration schedules to review further.

If the assessor finds, in any year, a reported price-per-unit of product outside of the range of the prices-per-unit being reported by other oil and gas taxpayers, the assessor can request additional supporting information and further documentation of the calculations used to establish the reported price-per-unit.

If the declarer fails to adequately respond to the assessor's requests for additional information, or if the final information supplied by the taxpayer does not support the reported value-per-unit, the assessor may establish a 100 percent leasehold interest value for the leasehold using the procedure for Best Information Available Assessments.

In the event that the assessor determines a value based on a quantity or wellhead selling price different than that reported by the taxpayer, the assessor may send the taxpayer a notice identifying omitted oil and gas value as omitted property. § 39-10-107, C.R.S. defines omitted oil and gas as, “underreporting of the selling price or the quantity of oil and gas sold therefrom.” This was affirmed by the Colorado Supreme Court in Kinder Morgan CO₂ Co Lp v. Montezuma County Board of Commissioners, Board of Assessment Appeals, and Colorado Property Tax Administrator, 396 P.3d 657 (Colo. 2017).

Oil and Gas General Audit Procedures

Counties are permitted to establish reasonable "audit" procedures to fairly and accurately determine the actual value of oil and gas leaseholds and lands. The county's audit program must include the following:

1. When a taxpayer is selected for audit, all of the taxpayer's wells within the same field or unitized operation are included, unless the scope of the audit is limited by agreement of both parties.
2. The county assessor provides a letter to the taxpayer, by certified mail, indicating that an "audit" of that taxpayer's oil and gas declaration will commence no sooner than 15 days after receipt of the letter. The audit notification letter must include:
   1. A listing of the assessment years under audit.
   2. A listing of the wells under audit.
   3. A listing of all pertinent records, including but not limited to, accounting, production sales, and tax records being requested by the county designated auditor.
3. Upon completion of the "audit," the county:
   1. Mails a notice of preliminary "audit" findings to the taxpayer at the address recorded on the annual declaration.
   2. Gives the taxpayer 30 days from the date of notice to submit additional information not considered by the county. The county may grant extensions of time upon request.
   3. Considers all additional information provided by the taxpayer to the assessor or to the county designated auditor.
   4. Provides a listing of the taxpayer's rights in the "audit" process. See below.
4. If a change in valuation is determined, the county uses the Division-approved Special Notice of Valuation, Special Protest Form, and Special Notice of Determination forms listed in ARL Volume 2, Administrative and Assessment Procedures, Chapter 9, Form Standards. If the county wishes to develop its own form(s), the Division of Property Taxation must approve each form prior to use.
5. If the taxpayer does not provide information or refuses to make information available, the assessor may:
   1. File in District Court under § 39-5-119, C.R.S., for a court order compelling the taxpayer to immediately cooperate with the assessor; or
   2. Issue a Best Information Available (BIA) assessment.

Oil and Gas Taxpayer Audit Rights

The county must provide the following rights to all taxpayers subject to an oil and gas "audit."

1. Taxpayers have 30 days to protest the value indicated on the Special Notice of Valuation. The county must consider all information supplied by the taxpayer in protest.
2. If a taxpayer files a protest, the county issues a Special Notice of Determination including a written explanation regarding the basis for the omitted property and the county’s decision. Language regarding a taxpayer’s appeal rights for filing an abatement petition is included in the Special Notice of Determination.

Other Review/Audit Procedures and Requirements

Oil and Gas Omitted Property Tax Collection Procedures

After the Special Notice of Valuation has been mailed and the 30-day taxpayer protest period has expired, the county may proceed to issue a tax bill to cover the omitted taxes.

Oil and Gas Confidentiality Requirements

All information or documentation provided to the assessor, the Property Tax Administrator, the annual study contractor hired under § 39-1-104(16), C.R.S., and/or their employees or agents, will be considered private and confidential under the provisions of § 39-7-101(4), C.R.S. Such information or documentation includes declaration schedules, accompanying exhibits, the Netback Expense Report Form (NERF), electronic or printed spreadsheet files, any documentation supporting the NERF, and any other information or documentation supplied as part of the audit or review process.

Contractual Arrangements

When agents are authorized by counties to perform audits or reviews, counties are to include language in audit contracts or legal agreements indicating that agents are bound by the provisions of § 39-5-120, C.R.S. Further, unauthorized release of any confidential information or documents is subject to the provisions of § 39-1-116, C.R.S.

Contingency fees are defined as fees paid to the agent that are based on the amount of omitted value discovered or taxes collected. Under § 39-10-107(1), C.R.S., counties are not permitted to contract with any agent wherein the audit fees paid to the agent are related, in any way, to the values reported on recorded properties, or to the tax amounts collected on omitted properties.

Overpayment of Taxes

If overpayment of taxes is discovered through the review or audit process, the county initiates an abatement petition in accordance with statutory abatement procedures. Abatements may be granted for taxes paid based upon the values established for the previous two (2) assessment years. Please note the following statute with regard to delinquent interest collected and/or refund interest due on abatement.

Abatement - cancellation of taxes.

(1)(b) Any taxes illegally or erroneously levied and collected, and delinquent interest thereon, shall be refunded pursuant to this section, together with refund interest at the same rate as that provided for delinquent interest set forth in section 39-10-104.5; except that refund interest shall not be paid if the taxes were erroneously levied and collected as a result of an error made by the taxpayer in completing personal property schedules pursuant to the provisions of article 5 of this title. Said refund interest shall accrue only from the date payment of taxes and delinquent interest thereon was received by the treasurer from the taxpayer; except that refund interest shall accrue from the date a complete abatement petition is filed if the taxes were erroneously levied and collected as a result of an error or omission made by the taxpayer in completing the statements required pursuant to the provisions of article 7 of this title and the county pays the abatement or refund within the time frame set forth in sub-subparagraph (B) of subparagraph (I) of paragraph (a) of this subsection (1). Refund interest on abatements or refunds made pursuant to sub-subparagraph (F) of subparagraph (I) of paragraph (a) of this subsection (1) shall only accrue on taxes paid for the two latest years of illegal or erroneous assessment (emphasis added).

§ 39-10-114, C.R.S.

If both underpayments and overpayments are discovered for different wells for the same taxpayer, the county may "offset," i.e., determine the net tax liability of or credit due, based on underpayments and overpayments, § 39-10-114(1)(a)(I)(E), C.R.S.

Division Review of Audit Procedures

Counties are to follow the previous procedures when reviewing or auditing taxpayer oil and gas declarations. If the county wishes to depart from one or more of the review or audit procedures, the county submits its changes to the Division for review prior to implementation.

Other Natural Resource Leaseholds & Lands

Properties in this section include the following:

1. Producing Coal Leaseholds and Lands, and
2. Producing Earth and/or Stone Products Leaseholds and Lands.

Statutory References

The statutes state how other (excepted) mines and operations extracting products excepted under § 39-6-104, C.R.S., are to be valued.

Valuation of mines other than producing mines.

(1) Mines excepted from the provisions of section 39-6-104 shall be valued for assessment in the same manner as other real property.

§ 39-6-111, C.R.S.

Other Natural Resources Discovery

Several good sources for the discovery of and information about natural resource properties and various types of mineral extraction operations are:

1. The Colorado Division of Reclamation, Mining, and Safety (DRMS), formerly The Division of Minerals and Geology, headquartered in Denver, is the best source for the discovery of pending and ongoing natural resource operations. They maintain data on mining operations statewide. Their reports contain information on location, acreages, reserve lives and mining plans. DRMS is also a good source of data for coal mines, with information on location, producing status, production tonnage, and properties of the coal being mined, e.g., BTU content. DRMS records are open for public inspection.
   
   The address of DRMS is:
   
   Division of Reclamation, Mining, and Safety
   Centennial Building
   1313 Sherman Street, Room 215
   Denver, CO 80203
   Telephone (303) 866-3567
   Division of Reclamation, Mining, and Safety Website
   
   A printout of currently permitted mining operations in the state can be accessed from the DRMS website. These operations include mines producing precious and base metals, coal mines, sand & gravel quarries and pits, other earth product operations, e.g., clay, and any extractive operations required to have a permit and be bonded for reclamation purposes. Refer to Addendum 6-I, Instructions for Accessing the DRMS Website, at the end of this chapter.
   
   This report provides owner and operator address, a legal location and the current status of the permit, e.g., active, terminated, temporary cessation, etc. Regardless of the current status listed in the report, every operation in the county should be physically inspected or mailed a declaration schedule to ensure all producing natural resources properties are assessed.
    
2. The County Clerk and Recorder's Office and County Planning Office may also have DRMS reports or pertinent information concerning natural resource operations available for public inspection.
    
3. The Colorado Geological Survey publishes maps, geological reports and general mine data on most natural resources within Colorado. Most of these resources are available online or through their bookstore. For more information, contact them directly at:
   
   Colorado Geological Survey
   Colorado School of Mines
   Moly Building
   1801 Moly Road
   Golden, CO 80401
   Telephone: 303-384-2655
   Colorado Geological Survey Website
    
4. The Colorado State Land Board handles the leasing of all natural resource operations on state land. Their office contains information on type of products mined, royalty rates, lessor's name, status of property, acres under lease, and location. The address is:
   
   Colorado State Land Board
   1127 Sherman Street, Suite 300
   Denver, CO 80203
   Telephone: (303) 866-3454
   Colorado State Land Board Website
    
5. One industry association that may be able to furnish names of contact persons for specific companies and general data about its industry is:
   
   Colorado Stone, Sand & Gravel Association
   6880 S. Yosemite Ct., Suite 100
   Centennial, CO 80112
   Telephone: (303) 290-0303
   Colorado Stone, Sand & Gravel Association Website

Other Natural Resources Site Analysis

After a natural resource property has been discovered, a general site analysis should be
completed prior to valuation. This analysis helps familiarize the appraiser with important
economic and physical characteristics about the operation. This information will also help to
substantiate the valuation done using the market or income approaches.

Recommended items for the analysis of a site are:

1. Location of the deposit.
   
   A large part of the delivered price per ton of minerals is transportation. The further away from the market, the greater the transportation costs. Its distance from the market directly affects the economic mine-ability of a mineral deposit.
    
2. Size and shape of the deposit.
   
   A mineral deposit must be of sufficient size to justify investment in its development. A mineral operation seeks a deposit with a physical life long enough to recover the investment in plant and equipment through depreciation. In addition, a mineral deposit must have sufficient depth of seam, limited overburden, and a low water table.
    
3. Economic demand for the mineral deposit.
   
   The life of a deposit is sensitive to the demands of the market place. For instance, clay is sensitive to style forces in its markets. One type of clay used in bricks may only be in style for three years. Then the style may change to a different color of clay.
    
4. Zoning or legal use.
   
   Federal, state or local land use regulations may restrict the location of and the access to mineral operations. A deposit may be of considerable size, of suitable quality and be located near a market but still have no value as a natural resource property due to legal use restrictions. You should note any regulations that may be applicable.
    
5. Stage of development.
   
   A parcel of land containing a large mineral deposit does not necessarily mean that the deposit adds value to the land. Unless the deposit can be recovered, processed and marketed at a profit, mining will not be feasible. In general, an undeveloped or partially developed mineral deposit will have less present value than a fully developed one with proven recoverable reserves and an established market.
    
6. Nature of the market.
   
   Some mineral operations are tied to a specific project with a limited duration. Road construction demands a great deal of gravel, but when the roads are completed the value of the pit may drop dramatically if additional demand is not present. In this example, the economic life of the deposit is directly related to the life of the project.

Other Natural Resources Classification

Mineral extraction operations that fall under the earth/stone product classification include all mines excepted under § 39-6-104, C.R.S.

If a coal mine is abandoned, there must be a map of abandonment filed with the Colorado Division of Reclamation, Mining, and Safety (DRMS) according to § 34-24-105, C.R.S. Terminated or abandoned earth/stone extraction operation will be listed on the DRMS extractive mineral operator’s listing. A printout of currently permitted mining operations in the state can be accessed from the DRMS website. Refer to Addendum 6-I, Instructions for Accessing the DRMS Website, for instructions.

Coal mines are classified as producing or nonproducing. Producing coal mines are mines that had production during the preceding calendar year. Nonproducing coal mines are those operations that have had no production in the previous calendar year, but have not filed a map of abandonment. Coal mines that have been abandoned and have filed a map of abandonment with the Division of Mines should be valued as all other real property according to the surface use of the property.

Taxpayer Filing Requirements

Specific information must be provided on a declaration schedule, filed no later than April 15 each year, by the operators of coal mines and earth/stone product operations. The DS 648 form is used for Earth/Stone Products; the DS 618 form is for Coal Leaseholds and Lands.

The natural resources property declaration schedules and appraisal records are used for both real and personal property data. Since confidential real and personal property information is contained on both the front and back of these declaration schedules, requests for non-confidential information should be directed to other public agencies which have access to this information and have the means of disclosing it to the public without divulging confidential information according to §§ 24-72-204(3)(a)(IV) and 39-5-120, C.R.S. Examples of these agencies might include, but are not limited to, the Colorado Division of Reclamation, Mining, and Safety (DRMS) or the Federal Bureau of Land Management.

Producing Coal Mines

Specific royalty rates and coal prices are included in Addendum 6-B, Coal and Other Rates and Prices, at the end of this chapter. These rates and prices must be used to value producing coal mines. For the proper application of the income formula, the following information must be known:

1. Raw tons of coal extracted (prior to beneficiation/washing).
2. Type of coal operation (underground or surface).
3. Type of coal being mined (steam or metallurgical).
4. If steam coal, the BTU content is needed.
5. Whether coal has been beneficiated (washed) to achieve the stated BTU rating. If the coal has been washed, the price listed in Addendum 6-B, Coal and Other Rates and Prices, is used and the washed tonnage should be used. If the coal has not been washed, the price in Addendum 6-B, Coal and Other Rates and Prices, should be reduced by $3.00 a ton and the non-washed tonnage should be used.
6. Estimated remaining economic life of the mine.

Valuation of Producing Coal Leaseholds and Lands

Producing coal leaseholds and lands must be valued by consideration of the three approaches to value. Inherent in the value of a producing coal mine will be any leasehold or possessory interest on public lands that is associated with, and an integral part of, the operation.

Income Approach

The income approach is considered the most indicative approach for valuing producing coal mines. This approach converts the future benefits of property ownership into an expression of present value. The benefits being measured are estimated economic royalty payments generated from the extraction of the coal over the remaining economic life of the mine. This methodology estimates annual economic royalty income based on the previous year's production, then capitalizes that income into value using a Hoskold factor to estimate the present worth of the permitted acres. This calculation is shown as follows:

Annual Economic Royalty Income x Hoskold Factor = Actual Value of Permitted Acres

The Mined Land Reclamation Board under the Colorado Division of Reclamation, Mining, and Safety (DRMS) has the authority to designate and permit extractive mineral operations under § 34-32-109, C.R.S. The permitted acres can include undisturbed lands, depleted lands and lands used for the operation.

Permitted Acres

The permitted acres are the total acres under permit by DRMS. These acres reflect the average of reserves underlying the surface of the permitted acres. There may be other surface uses occurring on the permitted acres that are not directly related to the mining operation. If any land within the coal operation’s permitted acres is used for purposes not directly related to the mining operation, that land separately valued based upon its highest and best use. Any improvements are classified and valued according to their use.

The number of permitted acres and the total parcel acreage will rarely match each other. However, the total acreage valued under each use must match the total acreage of the parcel. In order to classify properly, the valuation for the coal operation and any additional valuation for acres having another use must be separately shown on both the appraisal record and assessment roll. Acres valued under the producing coal formula should be classified as Producing Coal Leaseholds and Lands; other lands should be classified based on the use as of the assessment date.

Remaining Economic Life

An important part of the valuation process regarding producing coal mines is the estimate of remaining economic life. For each year's valuation, the assessor should consider both the physical depletion of the coal reserve, as well as economic factors such as future demand for the coal, market conditions, expense factors, and actual or potential environmental impact. Information on both physical and economic factors should be obtained from the mine operator. It is possible that, due to economic conditions, the economic life of a reserve may be substantially less than the physically mineable life.

If, after review of both physical and economic factors, the life of the coal reserve exceeds 30 years, a maximum life of 30 years should be used. If no estimate of reserve life is provided in the declaration, the life can be estimated by dividing the annual production into the total reserve tons declared.

Development of Hoskold Factors

The valuation of producing coal and earth and stone operations requires the assessor to convert the economic landlord income into value by multiplying the income by an applicable Hoskold factor. The resulting amount is the actual value of the producing operation’s permitted acres.

The Hoskold factor is composed of three components.

Discount Rate (return on the investment)
Sinking Fund Factor (return of the investment)
Effective Tax Rate (reflects property tax amount)

Each component is necessary to adequately reflect the appropriate return required by a lessor of coal reserves or earth and stone product mineral reserves.

The following steps should be used to calculate the appropriate Hoskold Factor:

1. Determine the current approved Discount Rate.
   
   The current approved Discount Rate can be found in Addendum 6-C, Hoskold Factors Worksheet, at the end of this chapter. The Discount Rate is researched and developed each year by the Division of Property Taxation.
    
2. Select the applicable Sinking Fund Factor.
   
   First, determine the remaining economic life of the deposit. (Refer to the Remaining Economic Life section for a more complete discussion of this issue.) Sinking Fund Factors for the current approved investment “safe rate” can be found in Addendum 6- C, Hoskold Factors Worksheet. Find and select the one factor in the Sinking Fund Factor column that corresponds to the remaining economic life of the reserve.
    
3. Calculate the Effective Tax Rate.
   1. Determine the mill levy for the year prior to the assessment date for the natural resource property being valued, based on the tax area in which it is located.
   2. Convert the mill levy to a decimal equivalent by dividing it by 1000.
   3. Multiply this number by the appropriate assessment rate and round to six decimal places. The resulting figure is the Effective Tax Rate.
4. Calculate the Effective Capitalization Rate.
   
   Add the Discount Rate, the appropriate Sinking Fund Factor, and the calculated Effective Tax Rate together.
    
5. Calculate the appropriate Hoskold factor.
   
   The appropriate Hoskold factor is calculated by taking the reciprocal of the Effective Capitalization Rate, i.e., "1" divided by the effective Capitalization Rate. This is the Hoskold factor to be used in the valuation formula.

*Effective tax rate calculation:

66.057 Example Mill Levy for producing coal operation

0.066057 Decimal Equivalent of Mill Levy x 0.29 Assessment Rate = 0.019157 Effective Tax Rate

Example:

0.116600 Discount Rate
0.017564 Sinking Fund Factor for 30 Years @4.09% Safe Rate
0.019157 Effective Tax Rate (rounded)*
0.153321 Effective Capitalization Rate

1 ÷ 0.153321 = 6.522276 Hoskold Factor

Hoskold rates for all coal and earth and stone product operations can be calculated using the tables in Addendum 6-C, Hoskold Factors Worksheet.

Income Approach Valuation of Producing Coal Leaseholds and Lands

An example of the income approach is presented below. Refer to Addendum 6-K, Coal Leaseholds and Lands Valuation Worksheet, or make a copy for your calculations.

The subject property in this example is an underground coal mine located in a Colorado county. The operator leases the land from the U. S. Forest Service. The operation sits on a 1,000-acre tract of land of which the entire 1,000 acres has been permitted by DRMS. The operator has filed a declaration schedule declaring 890,000 tons of production of 11,950 BTU coal. The remaining economic life of the mine is approximately 30 years, and the mine is located in a tax district with a mill levy of 66.057 mills.

Step #1: From Section E1 of the completed DS 618, determine the number of tons of coal mined during the preceding calendar year.

Step #2: Select the appropriate current Steam Coal Price/Ton based on the reported BTU content (Section G1) of the coal from Addendum 6-B, Coal & Other Rates and Prices.

Step #3: Multiply the Price/Ton by the number of tons mined to calculate the value of the coal produced.

Step #4: Multiply the production value by the correct current Royalty Rate, underground (6%) or surface (9%), found in Addendum 6-B, Coal & Other Rates and Prices, to calculate the royalty income to the landlord.

Step #5: Make a copy of Addendum 6-C, Hoskold Factors Worksheet, and develop the Hoskold factor to be used based on the remaining Economic Life in Years, Discount Rate, Sinking Fund Factor, and your Effective Tax Rate.

Step #6: Multiply the royalty income by the Hoskold factor to calculate the actual value of the producing coal mine (permitted acres).

Note: There is no assessment for the surface estate because land belonging to the U.S. Government is exempt.

Cost Approach

When a mine is under development, before production has occurred, the cost approach can be used. The cost of developing the mining property, as of assessment date, is added to the market value of the raw land to determine the cost approach valuation. All improvements should be valued and added to the land valuation.

Sales Comparison (Market) Approach

Consideration of the market approach involves the collection of any available sales of producing coal leaseholds and lands. Market data may be acquired from outside the state for comparable mines. Coal mines are usually sold as producing or nonproducing. The market data can usually be related to a value per ton of reserves.

There will be very few usable sales of mining properties. Most vacant land is bought and sold for other purposes. Be careful to choose a sale that has a current or imminent mineral use.

Most coal market sales include improvements. The comparable sales will have to be adjusted for inclusion or exclusion of improvements to reflect the subject property and make a valid market comparison.

Apportionment of Coal Real & Personal Property Values

Valuation and apportionment of the actual valuation for coal leaseholds and lands that lie in
more than one county shall be completed according to the following procedures:

1. The owner and/or operator of the producing coal mine must file a DS 618 Coal Leaseholds and Lands declaration schedule in all counties wherein the permitted acreage for the producing coal mine is located. Attached to this declaration must be a statement of permitted acreage, located within each county, as of the assessment date, and as allowed by the Colorado Division of Reclamation, Mining, and Safety (DRMS).
2. Valuation is to be done by the county wherein the main portal of the coal mine is located and must be done in accordance with the procedures contained in this chapter. That county is designated as the portal county.
   
   Copies of the valuation and apportionment calculation worksheets must be sent to the assessor(s) of the non-portal county(ies) for review. In case of disagreement between counties regarding how the valuation is calculated, the portal county will have the authority to make the final determination of value.
    
3. Apportionment of the coal leasehold and land reserve’s actual value to each county must be based on the total number of permitted acres within the producing mine boundaries. The actual value apportionment percentage is determined by dividing the acreage lying within each county divided by the total permitted acreage of the mine. Apportionment of the reserve value must be completed for each year coal is mined in the non-portal county(s).
   
   When the mining operation completes its mining of the portion of the reserve in the non-portal county and returns to mine reserves in the portal county, apportionment must be calculated through the end of the final year of production in the non-portal county and assigned to the portal and non-portal counties involved. Do not prorate production volumes or values based on completion or production end dates.
    
4. Actual value of improvements and fixtures must reflect a situs assessment basis; each county values and assesses those improvements that are located in their respective counties.
5. All personal property is reported to and valued by the portal county. The actual value of all personal property is apportioned to portal and non-portal counties using the same percentages as were used for the reserve value apportionment. In case of disagreement between counties, the portal county shall make the final determination of value.
   
   When apportionment between counties is no longer necessary, any above-ground personal property is assessed by the county where the property is located on the assessment date. Underground personal property is valued by the portal county and not apportioned.
    
6. If an assessment protest is filed by the owner and/or operator of the coal mine, this protest must be filed in both the portal and non-portal counties. Upon agreement of all assessors involved in the valuation, a consolidated hearing on the protest may be held at the office of the portal county assessor. In case of disagreement between counties, the portal county shall make the final determination regarding the protest.
   
   Appeals from the decision of the portal county assessor regarding the protest shall be made to both portal and non-portal counties. Upon agreement of all county boards of equalization involved in the valuation, a consolidated hearing on the protest may be held at the commissioners' office of the portal county. In case of disagreement between counties, the portal county shall make the final determination regarding the appeal.

All county assessors and respective county boards of equalization have the right to ask questions and request documentation of the taxpayer regarding any real or personal property issue.

Level of Value, Coal Leaseholds and Lands

All producing coal leaseholds and lands must be valued at current value using the manuals and associated data as supplied by the Division of Property Taxation, § 39-1-104(12.4), C.R.S.

Producing Earth/Stone Products Operations

Specific sand and gravel and road base (borrow) royalty rates are included in Addendum 6-A, Sand & Gravel Economic Royalty Rates, at the end of this chapter. These economic royalty rates must be used to value producing sand and gravel operations. Economic royalty rates for other earth/stone product operations are to be documented and developed locally by the
assessor. For the proper application of the income formula, the following information must be known:

1. Type of products being extracted.
2. Amount of each product extracted in tons or cubic yards.
3. Production royalty/percentage paid to the landowner or severed mineral interest owner for each product or, if owner-operated, price-per-unit in tons or cubic yards at first point of sale.
4. Estimated remaining economic life of the operation.

Valuation of Producing Earth/Stone Leaseholds & Lands

Minerals classified as earth or stone products include, but are not limited to the following:

• Asphaltum
• Clay
• Dawsonite
• Dolomite
• Feldspar
• Fluorspar
• Ganister
• Granite
• Gravel
• Gypsum
• Limestone
• Peat
• Perlite
• Quartz
• Road Base
• Rock
• Sand
• Soda Ash (nahcolite)
• Stone
• Turquoise
• Volcanic Scoria

Producing earth/stone leaseholds and lands must be valued by consideration of the three approaches to value. Inherent in the value of a producing earth and stone operation will be any leasehold or possessory interest on public lands that is associated with, and an integral part of, the operation.

Income Approach

The income approach is considered the most indicative approach for valuing producing earth/stone product operations. This approach converts the future benefits of property ownership into an expression of present value. The benefits being measured are estimated economic royalty payments generated from the extraction of the earth/stone product over the remaining economic life of the operation. This methodology estimates annual economic royalty income based on the previous year's production, then capitalizes that income into value using a Hoskold factor to estimate the present worth of the permitted acres. This calculation is shown as follows:

Annual Economic Royalty Income × Hoskold Factor = Actual Value of Permitted Acres

The Mined Land Reclamation Board under the Division of Reclamation, Mining, and Safety (DRMS) has the authority to designate and permit extractive mineral operations under § 34- 32-109, C.R.S. The permitted acres can include undisturbed lands, depleted lands, and lands used for the operation.

Permitted Acres

The permitted acres are the total acres under permit by DRMS. These acres reflect the average of reserves underlying the surface of the permitted acres. There may be other surface uses occurring on the permitted acres that are not directly related to the mining operation. If any land within the earth and stone operation’s permitted acres is used for purposes that are not directly related to the mining operation, that land is typically not separately valued. Any improvements are classified and valued according to their use. Land which is part of the total parcel acreage, but not part of the permitted acreage should be valued separately based on the land's classification, e.g., agricultural.

The number of permitted acres and the total parcel acreage will rarely match each other. However, the total acreage valued under each use must match the total acreage of the parcel. In order to classify properly, the valuation for the earth product operation (permitted acres) and any additional valuation for acres having another use must be separately shown on both the appraisal record and assessment roll. Acres valued under the producing earth/stone formula should be classified as Producing Earth/Stone Leaseholds and Lands; other lands should be classified based on the use as of the assessment date.

Remaining Economic Life

An important part of the valuation process regarding producing earth/stone operations is the estimate of remaining economic life. For each year's valuation, the assessor should consider both the physical depletion of the earth/stone reserve, as well as economic factors such as future demand for the product, market conditions, expense factors, and actual or potential environmental impact. Information on both physical and economic factors should be obtained from the operator. It is possible that, due to economic conditions, the economic life of a reserve may be substantially less than the physically mineable life. The following criteria should be considered when assigning an economic life for earth and stone operations:

• If, after review of both physical and economic factors, the life of a sand and gravel reserve exceeds 5 years, a maximum life of 5 years should be used.
• If, after review of both physical and economic factors, the life of any other earth/stone product reserve exceeds 30 years, a maximum life of 30 years should be used.
• If no estimate of reserve life is provided in the declaration, the life can be estimated by dividing the annual production into the total reserve tons declared.

Sand and gravel or borrow pits that are used intermittently, but may not have production every year, should have an economic life assigned based on the economically mineable reserves. For example, a pit with five years’ worth of reserves, which has only had production in three out of the last five years, would have a remaining economic life of two years. This pit would only be valued under the earth products formula when it had production in the previous year.

Use of Economic Royalty Rates

Economic royalty rates for sand and gravel and borrow operations are found in Addendum 6- A, Sand & Gravel Economic Royalty Rates, at the end of this chapter. These rates must be used to value all sand and gravel operations. The assessor must research economic royalty rates locally for all other earth or stone product operations.

In deciding whether to use the statewide borrow rate or the sand and gravel royalty rate, it is important to know the end use of the product, the extraction and subsequent processing method, and whether the royalty is paid by the ton or cubic yard.

Sand and gravel or other aggregate that is screened, sized, washed, crushed, sorted, or otherwise processed generally should be valued using the sand and gravel royalty rate. This sand and gravel is used for construction, concrete products, glass manufacture, and other purposes requiring a clean, uniformly sized aggregate. Royalty rates are generally paid by the ton of material extracted.

Borrow is material that is usually not processed in any manner subsequent to extraction. Often it will be loaded by front-end loader into a truck to be hauled directly to the jobsite. This material typically consists of a varied mixture of sand, gravel, clay, rock, soil, organic and other residual matter. It is generally used as fill or a base for roads or other improvements.

This material is typically not resold after extraction. Royalties are usually paid based on the number of cubic yards per truckload extracted. County road and bridge departments often contract with local landowners to extract borrow material for the maintenance and improvement of county roads.

Care should be used in distinguishing which rate to use. Material used as a base for a gravel county road should be valued as “borrow.” Material used as a chipseal coat or for winter sanding of paved roads should be valued at the sand & gravel rate. If the end use of the product is different than the product declared on the declaration schedule, documentation must be on file to support the end use.

Development of Hoskold Factors

The valuation of producing earth and stone operations requires the assessor to capitalize the economic landlord income to value by multiplying the income by an applicable Hoskold factor. The resulting amount is the actual value of the producing operation permitted acres.

The Hoskold factor is composed of three components.

Discount Rate (return on the investment)
Sinking Fund Factor (return of the investment)
Effective Tax Rate (reflects property tax amount)

Each component is necessary to adequately reflect the appropriate return required by a lessor of coal reserves or earth and stone product mineral reserves.

The following steps should be used to determine the appropriate Hoskold factor:

1. Determine the current approved Discount Rate.
   
   The current approved Discount Rate can be found in Addendum 6-C, Hoskold Factors Worksheet, at the end of this chapter. The Discount Rate is researched and developed each year by the Division of Property Taxation.
    
2. Select the applicable Sinking Fund Factor.
   
   First, determine the remaining economic life of the deposit. (Refer to the Remaining Economic Life section for a more complete discussion of this issue.) Sinking Fund Factors for the current approved investment “safe rate” can be found in Addendum 6- C, Hoskold Factors Worksheet. Find and select the one factor that corresponds to the remaining economic life of the reserve.
    
3. Calculate the Effective Tax Rate.
   1. Determine the mill levy for the year prior to the assessment date for the natural resource property being valued, based on the tax area in which it is located.
   2. Convert the mill levy to a decimal equivalent by dividing it by 1000.
   3. Multiply this number by the appropriate assessment rate and round to six decimal places. This number is the Effective Tax Rate.
4. Calculate the Effective Capitalization Rate.
   
   Add the Discount Rate, the appropriate Sinking Fund Factor, and the calculated Effective Tax Rate together.
    
5. Calculate the appropriate Hoskold factor.
   
   Take the reciprocal of the effective capitalization rate, i.e., "1" divided by the Effective Capitalization Rate. That is the Hoskold factor to be used in the valuation formula.

*Effective tax rate calculation:

66.057 Example Mill Levy for producing operation

0.066057 Decimal Equivalent of Mill Levy x 0.29 Assessment Rate = 0.019157 Effective Tax Rate

Example:

0.116600 Discount Rate
0.184295 Sinking Fund Factor for 5 Years @ 4.09% Safe Rate
0.019157 Effective Tax Rate (rounded)*
0.320052 Effective Capitalization Rate

1 ÷ 0.320052 = 3.124489 Hoskold Factor

Hoskold rates for all coal and earth and stone product operations can be calculated using the tables in Addendum 6-C, Hoskold Factors Worksheet.

Income Approach Valuation of a Producing Earth/Stone Operation

An example of the income approach is presented below. Refer to Addendum 6-L, Earth & Stone Product Worksheet section, or make a copy for your calculations.

The subject property is a sand and gravel operation located in a Colorado county in District #3. The operator leases the land being mined. The operation sits on a 160-acre tract. Twenty acres have been permitted by the Colorado Division of Reclamation, Mining, and Safety (DRMS). The balance of the land, outside the permit area, is agricultural and has been classified VIIA grazing, valued at $19.00 per acre. The operator has filed a declaration. The lease and reserves indicate the remaining economic life of the pit is 10+ years and the pit is located in a tax district with a mill levy of 66.057 mills. The maximum allowable economic life to be used is 5 years. The previous year’s production was 500,000 tons.

Step #1: From Section C of the completed DS 648, determine the number of tons of sand & gravel mined during the preceding calendar year.

Step #2: Select the appropriate Sand & Gravel Economic Royalty Rate per ton based on your District. Refer to Addendum 6-A, Sand & Gravel Economic Royalty Rates, for statewide districts and rates.

Step #3: Multiply the tons produced by that district’s Economic Royalty Rate to calculate the royalty income to the landlord.

Step #4: Make a copy of Addendum 6-C, Hoskold Factors Worksheet, and develop the Hoskold factor to be used based on the remaining Economic Life in Years, the current Discount Rate, the appropriate Sinking Fund Factor, and your effective tax rate.

Step #5: Multiply the royalty income by the Hoskold factor to calculate the actual value of the sand & gravel operation (permitted acres).

Step #6: Determine the value of the agricultural acres based on their use and productivity classification.

Step #7: List the value attributable to the sand & gravel operation with the permitted acres. List the agricultural value with the grazing acres. These values should be kept separate on the appraisal record, assessment roll, and for abstract purposes.

Example:

For sand and gravel operations, production is usually stated in tons. However, in those cases where production is in cubic yards, use a conversion factor supplied by the operator to calculate tonnage, or use the conversion factor found at the bottom of Addendum 6-A, Sand and Gravel Economic Royalty Rates, or contact the Division of Property Taxation.

This methodology should be used for operations that had production during the preceding calendar year. If no production occurred within the permitted acres during the preceding calendar year, the operation should be considered nonproducing and valued accordingly on the basis of current use.

Cost Approach

When an earth/stone product operation is under development, before production has occurred, the cost approach can be used. The cost of developing the mining property, as of assessment date, should be added to the market value of the raw land to determine the cost approach valuation. All improvements should be valued and added to the land valuation.

Sales Comparison (Market) Approach

Consideration of the sales comparison (market) approach involves the collection of any available sales of producing sand & gravel or earth products operations. The sales data can usually be related to a value per ton of reserves.

There will be very few usable sales of earth/stone product operations. Most vacant land is bought and sold for other purposes. Be careful to choose a sale that has a current or imminent mineral use.

Sales of sand & gravel pits may include equipment and improvements. The comparable sales will have to be adjusted for inclusion or exclusion of equipment and improvements to reflect the subject property and make a valid market comparison.

Level of Value, Producing Earth/Stone

All producing earth/stone product leaseholds and lands are valued at current value using the manuals and associated data as supplied by the Division of Property Taxation, § 39-1- 104(12.4), C.R.S.

Nonproducing Leaseholds and Lands

Nonproducing natural resource leaseholds and lands included under this section are:

1. Nonproducing Patented Mining Claims
2. Nonproducing Severed Mineral Interests
3. Other Nonproducing Natural Resource Leaseholds and Lands

Nonproducing Patented Mining Claims

The following subsections refer to the assessment of Nonproducing Patented Mining Claims.

Statutory References

The statutes are generally not specific covering nonproducing coal, earth/stone products, patented mining claims, and other nonproducing mines, leaseholds, and lands. These properties fall under the encompassing classification of "other real property" and, as is mentioned throughout articles 1, 6, and 7 of title 39, C.R.S., should be valued by consideration of the three approaches to value. The statutes specifically refer to the valuation of nonproducing mines, as paraphrased from § 39-6-111(2), C.R.S., all mines classified as nonproducing mines shall be valued for assessment in the same manner as other real property. The Colorado Constitution exempts nonproducing unpatented mining claims from taxation.

Uniform taxation - exemptions.

(1)(b)Nonproducing unpatented mining claims, which are possessory interests in real property by virtue of leases from the United States of America, shall be exempt from property taxation.

§ 3, article X, Colorado Constitution

In 1989, article 6 was amended with the addition of a new section, § 39-6-116 C.R.S., which attempts to clarify the constitutional language of article X, § (3)(1)(b). This section states “‘Unpatented mining claims’, as used in § 3(1)(b) of article X of the Colorado Constitution, includes mining claims located under the federal mining laws, 30 U.S.C. sec. 22 et seq., for which a patent has not been issued; and such term also includes leasehold interests in real property obtained under the federal ‘Mineral Lands Leasing Act of 1920,’ 30 U.S.C. sec. 181 et seq.”

Mining Claim Classification

Mining claims are of two types in Colorado:

1. Patented mining claims
2. Unpatented mining claims

A patented mining claim is land in which the United States government has conveyed fee simple title to private ownership. The intent of the U.S. government in granting title to owners of mining claims is for the purposes of extracting a mineral ore from the earth. However, owners of patented mining claims may use the surface land as any other private property.

In contrast, an unpatented mining claim is only a possessory interest in federal land in which the holder has the exclusive right to develop and extract minerals but may not use the land for any purpose other than mining.

According to § 39-6-103(2), C.R.S., mining claims, both patented and unpatented, comprising any part of a producing mine and contiguous to the producing mine are not to be assessed separately. Those unpatented claims that are part of a producing mine are included in the valuation for assessment of the producing mine. Nonproducing unpatented mining claims that are not part of a producing mine are exempt from property taxation under § (3)(1)(b), article X, Colorado Constitution.

Any leasehold interests that do not fit the definition of nonproducing unpatented mining claims under § 39-6-116, C.R.S., may be taxable. An example of such leasehold interests would be leaseholds obtained under the Mineral Leasing Act For Acquired Lands (30 U.S.C. Sec. 351 et seq.). The type of leasehold must be ascertained in order to determine its eligibility to be taxed.

Inquiries regarding the type of federal mineral leasehold should be directed to the following
address:

Bureau of Land Management
Colorado State Office
PO Box 151029
Lakewood, CO 80215
(303) 239-3600

Mineral leasehold information can also be accessed through the Mineral & Land Records System (MLRS) website.

Mining Claim Listing

According to § 39-6-103(1), C.R.S., the assessor is required to list all mining claims and mines
located within the county on the assessment date, whether entered for patent, patented or
unpatented. The statute requires the assessor to include the following information for each
claim:

1. Name of the lode, placer, mill site, or tunnel site.
2. The United States mineral survey number, if any.
3. Name of mining district.
4. Number of acres.

If two or more mining claims are included in one patent with one United States mineral survey number, the assessor must list all claims under the one number and include the total number of acres within the patent. When mining claims overlap, the acres must be allocated to the proper claim. Acreage of overlapping claims is decided by the earlier claim or patent number receiving the full acreage, according to the legal description. The overlapping area is deducted from the more recent claim.

Mining Claim Discovery

Patented mining claims are transferred through recorded documents in the same manner as other real property (land). Because a patent (deed) has been conveyed from the U.S. government, patented mining claims may be discovered by reviewing the recorded deeds in the County Clerk's office.

Claim Types

There are three types of claims recognized for patent by the federal government: placer, lode, and millsite. Specific requirements exist in applying for a patent for each type of claim.

Placer claims are those claims containing mineral deposits that are not in vein or lode formation. Typically these claims consist of a gold or other precious mineral-bearing gravel deposit. Placer claims are limited to 20 acres for each individual claim or a total of 160 acres for an "association" of claims.

Lode claims consist of mineral deposits in veins or lodes in the ground. Lode claims cannot exceed 1,500 feet in length or 600 feet (300 feet on either side of the middle of the vein) in width. This equates to a maximum surface area of 900,000 square feet, or 20.66 acres.

Millsite claims must be used or occupied for mining or milling purposes in conjunction with a valid mining claim. Millsites must be lands containing no mineral deposits. They can be patented along with lode or placer claims or patented by themselves. Millsites may not exceed five acres in size.

Patenting Claims

The procedure for patenting a mining claim is described in Part 3860 of title 43 of the Code of Federal Regulations (CFR). For additional information on the subject, refer to the CFR or contact your local Bureau of Land Management (BLM) office.

Mining Claim Site Analysis

If the claim is not used, or has no probable use for mining purposes, determine the land's current use, assign the appropriate land classification, and value in the same manner as all other property in that classification.

One of the most important factors in site analysis and classification is the determination of possible use as a residential/recreational site. Consistency is essential in distinguishing between land that should be classified as a patented mining claim and land with another most probable use.

The following criteria should be considered in the classification and valuation of the claim:

1. Zoning ordinances - does zoning prohibit or restrict mining (or residential use) in the area?
2. Size and shape of the claim - is the claim not so irregularly shaped or of such small size to allow construction of an improvement?
3. Desirability - is the claim desirable in terms of vegetation (tree cover), flowing water (creek/stream), slope aspect (south facing), etc., to a potential buyer?
4. Slope - is the slope of the land so steep as to be prohibitive of building or road construction?
5. Drainage and soil conditions - are drainage or soil conditions, i.e., rock, such that septic approval would be unobtainable?
6. Location of off-site improvements - are infrastructure improvements such as roads, power and telephone lines, etc., reasonably available?
7. Mining activity - is there any current or proposed, or has there been any recent mining activity on the claim?
8. Proximity to producing mining claims - is the claim close to any producing claims or in an active mining district?
9. Elevation - is the elevation of the claim so high that severe weather prevents or limits access?
10. Building permit - can a residential building permit be obtained for the claim?
11. Accessibility - is there existing road access to the claim or a reasonable possibility of constructing a road?
12. Water - can a well be drilled to obtain potable water?
13. Proximity to other dwellings - is the claim close to other houses, subdivisions, ranches, commercial establishments, etc?
14. Size - is the claim of sufficient size that the 35 acre platted subdivision rule does not apply?
15. Sale price - does the sale price compare favorably with other claims or vacant land sold for residential or recreational purposes?
16. Lease - is the claim being leased?

The above criteria should be considered selectively; not all criteria will apply to each county, or even each area. Certain factors may be given more weight than others. A rating system of importance of the various criteria may be developed with sufficient knowledge of the market.

Documented physical characteristics for all mining claims should be maintained. A comprehensive sales confirmation program can greatly assist in developing values. Care should be exercised in not valuing sold properties differently than unsold properties just because additional data has been received through a sales confirmation.

Accurate assessment maps can greatly aid in the site analysis and classification of mining claims. Topographic and other types of maps or overlays are valuable tools in determining site characteristics for each claim. Each claim or cluster of ownerships should be plotted on a map. Comparisons can then be made as to proximity to roads, existing improved residential/recreational sites, steepness and elevation of the land, mining districts and activity, etc.

A patented mining claim should not retain its classification and valuation as a patented mining claim unless it is used for, or the highest and best use would be for, mining purposes. Any nonproducing patented mining claim with an actual or most probable use as a mineral property should be classified and valued as such. If there is no apparent current use of the land, and further analysis does not reveal a probable future use, the land should be valued and abstracted as all other similar vacant land.

Valuation of Nonproducing Patented Mining Claims

Valuation of nonproducing patented mining claims must reflect the consideration of the three approaches to value.

Sales Comparison (Market) Approach

Providing there are sufficient sales, the market approach will usually give the best indication of value. The market approach involves direct comparisons of the property being appraised to similar properties that have sold. The steps to the market approach are provided below:

1. Discover and confirm sales of patented mining claims.
   
   Discovery involves continuous sales gathering. Sales must fall within the required eighteen-month to five-year data collection period. All transfers of patented mining claims should be compiled on a master list.
   
   Confirmation of sales price is imperative. All mining claim sales should be confirmed with the buyer or seller, and verified as valid arm’s-length transactions. Items to confirm include, but are not limited to, sales price, motivating forces, other forms of compensation verified such as stock options and future royalty rights, physical characteristics, existing leases, mineral rights, conditions of sale, etc. After confirmation of arms-length criteria and determination of physical characteristics, the valid sales should be compiled on a qualified list for analysis.
    
2. Select the appropriate unit of comparison. Research should be done to determine the basis on which mining claims are being bought and sold.
   
   Acres are the most common land unit of comparison for mining claims. Sites per claim or mineral reserves per ton of recoverable ore are other possible units of comparison.
    
3. Adjust the sales prices. The three primary types of adjustments are: time, location and physical characteristics.
   
   All sales must be adjusted for time to June 30th of the appropriate year's level of value. Location adjustments may involve adjusting sales price for such things as mining districts, zoning, areas of active lease or mining activity, etc. Physical condition adjustments could include slope, access, availability of off-site improvements, mineral reserves, size, etc. Other adjustments to sales may become apparent with further analysis. These could include adjustments for financing, leases on the property, etc.
   
   Values of mining claims do not remain constant. They fluctuate from time to time because of several factors including price and demand for the product, discovery of new reserves, amount of estimated reserves, and the likelihood of production. No sales price adjustments should be made without supporting documentation.
    
4. Correlate all sales data into an indicator of market value. The values should relate to the same unit of comparison, e.g., $/acre, $/claim, $/ton of reserves. A range of values may be needed to account for differences in size, location, or other physical characteristics.
   
   Statistical analyses will aid in determining the final value(s). After values have been set, a final statistical analysis should be calculated to ensure equality and uniformity of value has been achieved. All values should be applied consistently regardless of whether the property has sold or not.
   
   For a more detailed discussion of the sales comparison (market) approach refer to the Sales Comparison Method located in Chapter 2, Appraisal Process, Economic Areas, and Approaches to Value, of this manual.

Income Approach

Mining claims are sometimes leased for the purpose of exploration and development or speculative mineral value. These leases typically occur in areas of high mineral activity and may lead to an indication of value. The direct capitalization method lends itself to the valuation of mining claims under the income approach. The steps to the income approach to value are outlined below.

1. Discover and verify leases of mining claims. Leases will provide evidence of income to the claim owner.
   
   Most mineral leases will be recorded in the county clerk's office simply because it is in the best interest of the lessee to do so. However, often no mention is made of annual net rental to be paid.
   
   The lessor of a mineral lease is required to file an affidavit with the assessor stating the annual net rental payable, within ten days of the execution of a mineral lease, § 39-5- 115(2), C.R.S. The assessor has the right and authority, under §§ 39-5-115 and 39-5- 119, C.R.S., to request additional information on the mineral lease, whether or not an affidavit is filed by the lessor.
   
   The terms of the mineral leases should be confirmed with the lessor or lessee in the same manner as the sales are verified in the market approach. Confirm all terms of the lease including annual land rental and future royalty rights.
    
2. Determine the effective gross income from the lease. Thorough research should be performed to identify the typical land rental. Adjustments may be required for different lease terms in determining what is typical for an area. Effective gross income for a mining claim is calculated by multiplying the land rental per acre by the number of acres of the claim(s).
    
3. Deduct all typical allowable expenses from the lease income to determine net income. Typically, there are little or no management expenses involved in mineral lease income. In most instances, legal fees and property taxes are the only expenses to the holder of the claim. Property taxes will be considered in the development of the capitalization rate and should not be deducted from effective gross income.
   
   Expenses should be represented as a percentage of gross income or broken down on a $/acre basis.
    
4. Develop the capitalization rate. The effective tax rate (ETR) should be calculated and added to the discount rate for the capitalization rate to be used in the formula.
   
   The Discount Rate to be used is published annually by the Division in Addendum 6-C, Hoskold Factors Worksheet. The Effective Tax Rate must be calculated by the county.
   
   Documentation for use of a different discount rate or a locally developed overall capitalization rate must be submitted to the Division for approval prior to use.
    
5. Capitalize the net income into an estimate of value. This is calculated by dividing the net income by the capitalization rate.

An example of this procedure is shown below.

Example:

Mill levy (decimal equivalent) x assessment rate = ETR
Discount rate + ETR = Capitalization rate

Economic Annual Net Rental
Economic Annual Net Rental Capitalization Rate = Actual Value

0.045^A x 0.29 = 0.01305 rounded to 0.013
0.1166^B + 0.013 = 0.1296
$2.00^C ÷ 0.1296 = $15.50 per acre actual value (rounded)

$15.50/acre x 20^D acres = $310 actual value for claim

^A Assumed mill levy of 45 mills for example only.
^B Refer to Addendum 6-C, Hoskold Factors Worksheet for the appropriate discount rate. The effective tax rate must be separately calculated and added to the discount rate to equal the capitalization rate.
^C Determined from analysis of mining claim leases within the county.
^D Example size of a patented mining claim. The acreage of each claim should be calculated prior to valuation.

Cost Approach

When a patented mining claim(s) does not generate more than $5,000 of gross proceeds worth of production, the cost approach may be considered. The cost of developing the mining property, as of the assessment date, should be added to the market value of the raw land to determine the cost approach valuation. All improvements should be valued and added to the land valuation.

Level of Value, Nonproducing Patented Mining Claims

All nonproducing patented mining claims must be valued at the specified year's level of value using the manuals and associated data supplied by the Division of Property Taxation.

Actual value of nonproducing patented mining claims is to be correlated to the end of the data collection period as specified in statute. The appraisal date for this class of property is June 30 of the year prior to the year of reappraisal. Exact wording of the level of value is contained in § 39-1-104 (10.2) through (12.4), C.R.S.

Nonproducing Severed Mineral Interests

Severed mineral interests are separate ownerships of minerals in place and do not include surface land. Colorado statutes require the assessment of nonproducing severed mineral interests and provide for their valuation.

Statutory References

Severed Minerals

Severed mineral interests, other than oil and gas interests, must be valued by consideration of the three approaches to value, § 39-1-103(5), C.R.S.

Lessors of severed minerals are required to file rental information with the county assessor.

Taxpayer to furnish information - affidavit on mineral leases.

(2) Within ten days after the execution of a mineral lease, a lessor shall file with the assessor an affidavit stating the annual net rental payable under such lease for the purposes of determining the actual value of such mineral interest where the income approach to appraisal is utilized by the assessor. Such affidavit shall constitute a private document and shall be available on a confidential basis as provided in section 39-5-120.

§ 39-5-115, C.R.S.

Any taxpayer who owns land where some or all of the mineral estate has been severed can require the assessor to place the mineral interest on the tax roll, § 39-1-104.5, C.R.S. Proof of ownership and the record of creation of the severed mineral interest must be provided to the county assessor.

Additional information regarding the sale and purchase of severed mineral interest tax liens can be found in § 39-11-150, C.R.S.

The statutes require sole use of the income approach to value severed nonproducing oil and gas mineral interests, § 39-7-109, C.R.S. The annual net rental is to be capitalized at an appropriate market rate.

The statutory definition of "annual rental" for severed nonproducing oil and gas mineral interests is found under § 39-7-109(2), C.R.S. It is virtually identical to the definition of "annual rental" for nonproducing oil shale mineral interests found under § 39-1-103(12)(b), C.R.S. Refer to Minerals in Place below.

Minerals in Place (Mineral Reserves)

Colorado statutes define minerals in place as follows:

Definitions.

(7.9) "Minerals in place" means, without exception, metallic and nonmetallic mineral substances of every kind while in the ground.

§ 39-1-102, C.R.S.

The Colorado legislature specifically declares that, in cases where consideration of the three approaches to value fails to indicate an actual value for the mineral in place, the surface use of the property will be the determining factor when valuing land.

Legislative declaration.

[W]hen appropriate consideration of the three approaches to value fails to derive an actual value for such property, the actual value of such property shall be determined by comparison of the surface use of such property to property with a similar surface use.

§ 39-1-101, C.R.S.

This declaration is further reiterated in § 39-1-103(5), C.R.S.

In valuing real property, minerals in place are not to be considered in determining the actual value of such real property unless the assessor can produce evidence that inclusion of the value of the minerals in place results in uniform, just and equal values, § 39-1-103(11), C.R.S. In valuing oil shale mineral interests, limitations regarding the application of both the market and income approaches are specifically set forth in Colorado statutes.

The sales comparison (market) approach for valuing nonproducing oil shale mineral interests is constricted by the requirement of a minimum of five arm’s-length sales, § 39-1-103(8)(a)(II), C.R.S.

When using the income approach to value nonproducing oil shale mineral interests, the assessor is required to capitalize the annual rental payments at a rate of thirteen percent, § 39-1- 103(12)(a), C.R.S. Bonus payments or royalty payments of any kind are not to be included in the net income capitalized under the income approach, § 39-1-103(12), C.R.S.

Severed Mineral Interest Discovery

The most common method of discovering severed mineral interests is a careful review of deeds recorded in the county clerk's office. Minerals are usually severed from the surface by means of a "reservation" in a land deed, or by a separate document called a “mineral deed.” Obtaining a complete up-to-date listing of severed mineral interests requires a title search of all conveyances of land from the original patent to the present owner's deed.

Severed Mineral Interest Listing

Severed mineral interests should be listed on a separate schedule for each interest. This will help eliminate double or omitted assessments as a result of additional separation of property rights.

Determination of Net Mineral Acreage

Severed mineral interests are generally expressed as an undivided fractional interest in a certain amount of acres. To value severed minerals on a per-acre basis, the legal description on the mineral deed must be converted to an acreage equivalent.

Example:
A severed mineral interest was purchased. The mineral deed described the property as 768/4096 interest in a half-section of land containing 320 acres.

How many net mineral acres are owned?

768 ÷ 4096 = 0.1875 or 18.75%
320 acres x 0.1875 = 60 net mineral acres

Valuation of Nonproducing Severed Mineral Interests

Nonproducing severed mineral interests, except severed nonproducing oil and gas mineral interests, are to be valued in the same manner as other real property; through the appropriate consideration of the cost, market, and income approaches to value.

Sales Comparison (Market) Approach

This approach should give a good indication of the value of severed mineral interests, provided there are sufficient sales. The market approach involves direct comparisons of the property being appraised to similar properties that have sold in the same or similar market. Market sales occur more frequently in areas of high interest. The market approach will be most appropriate in these areas and may not be applicable in areas of low activity. The steps to the market approach are provided below:

1. The market approach involves continuous sales gathering. Values of severed mineral interests do not remain constant. They fluctuate from time to time because of several factors, including price and demand for the product, discovery of new reserves, amount of estimated reserves, and the likelihood of production.
2. Confirmation of sales price is imperative. All severed mineral interest sales should be confirmed with the buyer, seller, or both in order to verify sales price, motivating forces, and other forms of compensation such as stock options and future royalty rights.
3. Determine what minerals are being conveyed in the transaction. Sales involving the rights to any and all minerals should be segregated from those sales of only a certain type of mineral right.
4. Check sales for arm’s-length criteria. An arm’s-length transaction is a transaction arrived at in an open market between unrelated parties under no duress. Sales that do not meet the criteria for an arm’s-length transaction should be deleted from analysis.
5. Arrange the sales by area. Do not attempt to assign the same market value to all severed minerals unless sales prices are consistent throughout the county. Use of market data may result in different values for different areas. Adjustment factors should be developed to adjust comparable sales to the subject.

Two statutory limitations exist that restrict or eliminate the market approach in valuing certain types of severed mineral interests. In the valuation of nonproducing oil shale mineral interests, § 39-1-103(8)(a)(II), C.R.S., requires that a minimum of five (5) arm’s-length sales of comparable oil shale mineral interests exist to constitute a market for the use of the market approach. In valuing severed nonproducing oil and gas mineral interests, § 39-7-109(1), C.R.S., precludes the use of the market approach.

Income Approach

Income attributable to the leased mineral interests must be used to estimate the value of severed
mineral interests. For severed nonproducing oil and gas mineral interests, this is the only
method allowed by statute. The steps to the income approach to value are outlined below.

1. The lessor of a mineral lease is required to file an affidavit with the assessor stating the annual net rental payable within ten days of the execution of a mineral lease. As a check, search leases recorded in the county clerk's office. Most mineral leases will be recorded simply because it is in the best interest of the lessee to do so.
2. The terms of the mineral leases should be confirmed with the lessor or lessee in the same manner as the sales are verified in the market approach. Confirm all terms of the lease including annual land rental and future royalty rights.
3. Determine the effective gross income from the lease. Thorough research should be done to identify the typical land rental. Bonus money or advanced royalty payments are not to be considered in estimating the future income.
4. Deduct all typical allowable expenses from the lease income.
   
   There is little or no management expense involved in mineral lease income. In most instances, legal fees and property taxes are the only expenses to the owner of the severed minerals. Property taxes will be considered in the development of the capitalization rate and should not be deducted from effective gross income.
    
5. Develop the capitalization rate. The effective tax rate (ETR) should be calculated and added to the discount rate for the capitalization rate to be used in the formula.
6. Capitalize the net income into an estimate of value.

An example of this procedure is shown below.

Example:

Mill levy (decimal equivalent) x assessment rate = ETR

Discount rate + ETR = Capitalization rate

Economic Annual Net Rental
Capitalization Rate = Actual Value
0.045^A x 0.29 = 0.01305 rounded to 0.013
0.1166^B + 0.013 = 0.1296
$2.00^C ÷ 0.1296 = $15.50 per net mineral acre actual value (rounded)

^A Assumed mill levy for example only.
^B Refer to Addendum 6-C for the appropriate discount rate. The effective tax rate must be separately calculated and added to the discount rate to equal the capitalization rate.
^C Determined from analysis of severed mineral leases within the county.

If the taxpayer owns 60 net mineral acres, the assessed value is computed as follows:

60 x $15.50 = $930 Actual value (rounded)
$930 x 0.29 Statutory assessment rate = $270 Assessed value (rounded)

Severed Mineral Interests in Production

When natural resource land is valued for assessment solely on the basis of production during the previous year, an additional separate assessment of the severed mineral interests would constitute double assessment of the minerals. There should not be a separate assessment of severed mineral interests during the years of mineral production. This also applies to separately owned tracts or interests that do not have mineral production but are embraced in all or part of a drilling or production unit through a pooling agreement, or pooling order pursuant to §34-60-116 (6), C.R.S., from which there is production. However, if the severance is for a mineral not under production, the severed mineral interest must be assessed separately.

Level of Value for Nonproducing Severed Minerals

All nonproducing severed mineral interests must be valued at the specified year's level of value using the manuals and associated data as supplied by the Division of Property Taxation.

Actual value of nonproducing severed mineral interests is to be correlated to the end of the data collection period as specified in statute. The appraisal date for this class of property is June 30 of the year prior to the year of reappraisal. Exact wording of the level of value is contained in § 39-1-104 (10.2) through (12.4), C.R.S.

Other Nonproducing Natural Resources

All other natural resource property not already included under other classifications would fall in this category. Properties under this classification include the following:

1. Mines with gross proceeds of $5,000 or less.
2. Minerals in place where the mineral estate has not been severed from the surface estate.
3. Operations that had no production the previous year but have not been abandoned.
4. Natural resource operations in the development stage.
5. Nonproducing possessory interest leaseholds on government lands.

Statutory References

The statutes are generally not specific covering nonproducing coal, earth/stone products, patented mining claims, and other nonproducing mines, leaseholds, and lands. Refer to discussion regarding federal mineral leaseholds. These properties fall under the encompassing classification of "other real property" and, as is mentioned throughout articles 1, 6, and 7 of title 39, C.R.S., should be valued by consideration of the three approaches to value.

In valuing other nonproducing mineral properties, the burden of proof for the value of the minerals falls upon the assessor. This is stated several times in the statutes under §§ 39-1-103 and 39-1-104, C.R.S., in basically the same language as § 39-6-111, C.R.S.

Valuation of mines other than producing mines.

(3) Such valuation shall be determined under this section by the assessing officer only upon preponderant evidence shown by such officer that the cost approach, market approach, and income approach result in uniform and just and equal valuation.

§ 39-6-111, C.R.S.

"Preponderance of the evidence" is defined in Black's Law Dictionary, 7th Edition, as "The greater weight of the evidence; superior evidentiary weight that, though not sufficient to free the mind wholly from all reasonable doubt, is still sufficient to incline a fair and impartial mind to one side of the issue rather than the other.”

If uniform, just and equal values of the subsurface rights cannot be substantiated; the land should be valued based only on surface use using the three approaches to value. The preponderant evidence limitation applies to subsurface resources only. A general site analysis will help to provide documentation to satisfy the preponderant evidence requirement.

Classification, Listing, Discovery, Site Analysis

The process of classifying, listing, discovering, and performing a site analysis for these types of properties is similar to that found in other parts of this chapter.

Increased diligence will be required to discover these types of properties. However, many of the same discovery sources used for producing operations will be valuable in locating these nonproducing natural resource properties.

Care should be taken when these types of properties are encountered to ensure proper listing and classification. Illegal or double assessments are problems that could occur. The value of minerals in place, if supported by preponderant evidence, would be added to the value of the land determined from the surface use.

Possessory interests on government lands have been assigned an abstract classification of their own. Many of the other properties will fall into the vacant land abstract classification. With the exception of Possessory Interests, all other abstract classifications under the Natural Resource category should be reserved for producing operations.

After a natural resource property has been discovered, a general site analysis should be completed prior to valuation. This analysis helps familiarize the appraiser with important economic and physical characteristics about the operation. This information will also help to substantiate the valuation done using the market or income approaches and provide the necessary "preponderant evidence" to satisfy statutory requirements.

Other Nonproducing Natural Resources Valuation

All nonproducing natural resource leaseholds and lands should be valued by consideration of the three approaches to value. The following is a brief analysis of the approaches to value as they relate to these types of properties:

1. When a natural resource operation is under development, or has ceased operation the cost approach can be used. The cost of site improvements should be added to the market value of the raw land to determine the cost approach valuation. All improvements should be valued using the cost approach and added to the land valuation.
2. The market approach to value is suitable when adequate market information exists. Sales do occur occasionally and market information should be gathered, verified and analyzed.
3. The income approach is often considered for natural resource properties due to their unique nature and the general lack of market sales. The income approach converts the future benefits of property ownership into an expression of present value.

Nonproducing mines and mineral extraction operations are:

1. Operations that have not produced during the preceding calendar year and have not been abandoned, or
2. Mines with production that do not qualify under the statutory definition for a producing mine, i.e., those with less than $5,000 in gross proceeds.

Nonproducing mines and operations are to be valued by the consideration of the three approaches to value.

The value of any mineral reserves may contribute to the total value of the nonproducing land. This value, which is attributable to the minerals in place, would be part of the sales price or capitalized lease income in an active mineral market. Lack of market sales or leases involving mining companies or partnerships would indicate the nonproducing land should be valued primarily based on surface use.

Level of Value, Other Nonproducing Natural Resources

All nonproducing mines and leaseholds and lands must be valued at the specified year's level of value using the manuals and associated data supplied by the Division of Property Taxation.

Actual value of other nonproducing natural resource property is correlated to the end of the data collection period as specified in statute. The appraisal date for this class of property is June 30 of the year prior to the year of reappraisal. Exact wording of the level of value is contained in § 39-1-104 (10.2) through (12.4), C.R.S.

Nonmineral Natural Resource Properties

Timber

Colorado Statutes do not specifically provide for the valuation and taxation of timber products or production. Forest product production is associated with a multitude of land uses including residential, agricultural, and commercial. This production is not considered a separate type of Natural Resource property and is not listed as a sub-classification on the abstract of assessment.

In the valuation of land for ad valorem purposes, any timber value existing on the land is recognized in the market value of the land and is not to be separately appraised or valued for assessment.

Criteria and procedures for the valuation of forest lands, as opposed to timber production, can be found in § 39-1-102(1.6)(a)(II), C.R.S. Please refer to Chapter 5, Valuation of Agricultural Land, for additional guidelines.

Water Rights

In the past, the valuation and assessment of water rights was included in the natural resource valuation section. However, they are now considered in the valuation process used for assessment of the real property served. Please refer to Chapter 7, Special Issues in Valuation, for more specific information on the valuation of water rights.

Geothermal

Colorado Statutes do not specifically discuss how geothermal leaseholds and lands are to be valued. Geothermal resources are not to be appraised and valued separately, but should be appraised and valued with the real property (land) as a unit. Consideration of the three approaches to value is required in the valuation of any geothermal resources.

Addendum 6-A, 2024 Sand & Gravel Economic Royalty Rates

District #1 - $.99 per ton
Counties:

• Adams
• Arapahoe
• Boulder
• Broomfield
• Clear Creek
• Denver
• Douglas
• El Paso
• Elbert
• Gilpin
• Jefferson
• Larimer
• Weld

District #2 - $.74 per ton
Counties:

• Kit Carson
• Logan
• Morgan
• Phillips
• Sedgwick
• Washington
• Yuma

District #3 - $.71 per ton
Counties:

• Baca
• Bent
• Cheyenne
• Crowley
• Custer
• Fremont
• Huerfano
• Kiowa
• Las Animas
• Lincoln
• Otero
• Prowers
• Pueblo

District #4 - $1.29 per ton
Counties:

• Alamosa
• Archuleta
• Conejos
• Costilla
• Dolores
• La Plata
• Mineral
• Montezuma
• Ouray
• Rio Grande
• Saguache
• San Juan
• San Miguel

District #5 - $1.30 per ton
Counties:

• Chaffee
• Delta
• Eagle
• Garfield
• Grand
• Gunnison
• Hinsdale
• Jackson
• Lake
• Mesa
• Moffat
• Montrose
• Park
• Pitkin
• Rio Blanco
• Summit
• Teller

Statewide royalty rate for borrow - $.60 per cu. yard

To convert tons to cubic yards: tons x .74 = cubic yards
To convert cubic yards to tons: cubic yards ÷ .74 = tons

Addendum 6-B, 2024 Coal & Other Rates and Prices

Coal

Royalty Rates: 6% of market price underground
9% of market price surface (strip)

Discount Rate: 11.66%*

A deduction of $3.00 per ton from the above listed prices should be made if the coal operation does not beneficiate (wash) the raw coal produced to achieve a saleable product. If this deduction is taken, the assessor must use raw production tonnage (pre beneficiation) as reported by the mine owner or operator when using the income approach to value the mine.

Other Natural Resource Operations

Discount Rate – 11.66%

*This discount rate is listed to provide the appraiser with one of the three components needed to locally develop an applicable Hoskold factor. Please refer to Development of Hoskold Factors located in this chapter for specific instructions on development of the Hoskold factor.

Addendum 6-C, 2024 Hoskold Factors Worksheet

Discount Rate = 11.66%
Sinking Fund Factors @ 4.09%

Addendum 6-H, Accessing the ECMC Website

The ECMC Internet website can be used as an alternative source for discovery of new wells, or as a confirmation source for submitted declarations. Both current and prior year production information can be viewed and printed. The website can be accessed by following these steps:

Step #1 Access the ECMC website main screen.

Step #2 Click on the Data tab located below the banner of the main ECMC screen to access the Colorado Energy and Carbon Management System (COGIS).

Step #3 Under the topic heading Inquiry, click on the sub-heading Production to access the COGIS - Production Data Inquiry screen.

Step #4 Under the Display Production According to, click on the type of search you want to do: Well, Facility/Lease, Operator, County, or (Oil) Field. Then, enter the range of years, e.g., 2011 - 2011 for the year 2011, or 2012 - 2012 for the year 2012.

Step #5 Next, you can either click on your county in the County Window, or enter your three-digit county code as assigned by ECMC in the County Code box under Enter search criteria. The ECMC county codes are listed below:

By taking the ECMC Operators Number off of the DS-658, you can search by Operator Number by typing it in the Operator box, and clicking on Number. Be sure to select “Unlimited Records” in the Limit Records box at the bottom of the screen or you may miss some of the data.

Step #6 Click on the Submit button to send your inquiry request. This will bring up the production, by Well, for all wells for the selected operator, for the selected year. This can be matched against the information the operator provided on the DS- 658.

To search for New Operators or New Wells in your county, search either by County or by Township and Range. In a County with more than a few hundred wells, it would be better to search by Range only, or even by Township and Range only. Again, select “Unlimited Records” in the Limit Records box at the bottom of the screen. Click on the Submit button to send your inquiry request. This listing may be printed using the Print command in your web browser. Printing should be done in Landscape mode.

For counties with a large number of wells, processing the request may take a few minutes. These counties should try to access the ECMC database early in the morning or late in the evening when fewer users are online.

Your query may take several minutes to compile and/or may terminate with an error message [error ‘ASP 0113’ Script timed out. The maximum time for a script to execute was exceeded]. If this happens, re-enter the query request and limit the query by Section, Township, and Range, or some other parameter.

Note: When in any of the COGIS screens, clicking on a word or field that COGIS has highlighted in blue will take you to further screens with more information. For instance, click on the blue-highlighted year “2005” to access the COGIS – Monthly Well Production for that well. Then clicking on the blue-highlighted Facility Name will bring up the COGIS – Well Information screen. This screen contains individual well surface location information for that well and/or drilling location. Information about the depth of the well (Measured TD) can be obtained here for use in valuing wellsite equipment using the BEL grids. If your computer has software to access GIS maps, clicking on GIS will bring up a GIS map showing where the well is located.

If you have any questions, or have trouble accessing the information you seek, please call the Division of Property Taxation at (303) 864-7777 and ask for an Oil and Gas Property Tax Specialist.

Addendum 6-I, Accessing the DRMS Website

In 2006, The Division of Minerals and Geology (DMG) changed its name to the Division of Reclamation, Mining, and Safety, under § 34-32-105, C.R.S. For discovery of new mining operations, the Division of Reclamation, Mining, and Safety (DRMS) Internet website should be used. The website may be accessed, and a current listing of mining operators printed, using the following steps:

Step #1 Access the DRMS website main screen

Step #2 Click on the Data Search located in the main navigation bar.

Step #3 On the Data Search screen, under “Permit Database Searches” select “Search by County.” Searches can also be performed by permittee/operator, permit number, or site name. Other reports and GIS information is also available on the Data Search screen.

Step #4 On the second screen in the County box, click on the arrow to the right of the box and select your county. Likewise, go to the Permit Status box and select the permit status. (All is recommended.) Next, go to the Commodity box and select the commodity for the report. (All Commodities is recommended.) Be sure that “Operator/Permit Number” is selected below the boxes. Then click on View Report to view the DRMS mining operators report for your county. 

If you have trouble accessing the DRMS Mining Reports on line, please contact the Division of Property Taxation, Natural Resources Property Tax Specialist at (303) 864-7777.

Addendum 6-J, Oil & Gas 2024 Netback IG Corporate Bond Rate, 2024 NERF, and NERF Spreadsheet Instructions

The oil and gas threshold rate for Return on Investment (ROI) calculations for the 2024 assessment year is 5.38 percent. The rate is calculated from the monthly average IG Corporate bond yields from October 2022 through October 2023 as found in Standard and Poor's Corporate Bond Index.

Oil and gas operators and take-in-kind royalty owners are allowed their actual 2023 calendar year rate of return up to the published rate. Actual rates of return on investment in excess of this published rate must be restated to the published rate prior to calculating the allowed ROI deduction.

Netback Expense Report Form (NERF)

The use of the NERF by county assessors is optional or at the assessor's discretion. If the assessor chooses to request completion and submission of a NERF, the form may be mailed, either with the DS 658 Oil and Gas Real and Personal Property Declaration Schedule or later in the year after the declaration schedules are received, to all oil and gas producers that are using either the unrelated party, comparable expense deduction, or related party netback methods to determine the netback wellhead price reported on the declaration schedule. If completion of the NERF is requested from the producer, the required filing deadline is 30 days after the date of the request, but no earlier than the statutory filing deadline for the declaration schedule which is April 15th. If the NERF is sent along with the declaration schedule, it should be mailed to the oil and gas producers as soon as practicable after January 1 of each year. However, the NERF may be mailed at any time during the current assessment year. A blank NERF and its accompanying Supplemental Information Report Form (SIRF) follow this page. Instructions for completion of the forms are included on the back of the forms.

Instructions to Access NERF Spreadsheet Online

In lieu of using the NERF, an electronic NERF Spreadsheet is available to taxpayers as an optional, but not mandatory, information source to supplement the DS 658, Oil & Gas Real and Personal Property Declaration Schedule. If the assessor’s office requests completion of a regular NERF by a taxpayer, the taxpayer may submit a completed electronic NERF Spreadsheet instead. The electronic NERF Spreadsheet may be accessed and downloaded from the Division’s website:

Property Taxation Forms Index

After reaching the Division’s “Forms” page, select “NERF Spreadsheet.” The spreadsheet is downloadable by opening it, selecting “Save As,” and saving it to a folder in your local computer. The “NERF Spreadsheet” is an Excel File. After closing the connection to the Internet, you may open the spreadsheet by going through Excel and opening the file in the folder where it was placed. It will then be ready for your input.

After opening the “NERF Spreadsheet,” you will notice that the file consists of ten worksheets with tabs at the bottom titled:

• Instructions
• NERF Spreadsheet
• NGL Worksheet
• Netback Expenses
• Assessment Analysis
• Selling Price Analysis
• Equipment
• Tank Battery
• Stored Equipment
• Leased Equipment

The worksheet marked “Instructions” explains how the other worksheets are used. As the taxpayer completes the worksheets labeled “NERF Spreadsheet,” “NGL Worksheet,” and “Netback Expenses,” pertinent information from these worksheets is automatically transferred to the “Assessment Analysis” and “Selling Price Analysis” worksheets, which are used primarily by the assessor’s office. Note that the spreadsheet is adaptable for any assessment year. The taxpayer is required to input the IG Corporate BondRate published by the Division for the assessment year chosen for the submission. Please see the NERF Spreadsheet “Instructions” for further clarification.

2024 Oil and Gas Netback Expense Report Form

Netback Expense Report Form (NERF)

Taxpayer Instructions

Rev 1/24

This form is designed for providing written documentation supporting netback wellsite processing, gathering, off-site processing, and transportation expenses deducted by Colorado oil and gas producers to determine wellhead selling prices for property tax purposes. This form has been created for and must be completed to procedures developed under 39-7-101(1)(d), C.R.S. Netback information should be filed on a per well basis. However, this information may be filed on a lease or unitized field basis provided all wells contained within the lease or unitized field are listed separately for review by the assessor and gross sales prices and netback expenses are allocated to each well so that the netback wellhead selling price reported matches the price reported on the DS 658 Oil and Gas Declaration Schedule submitted to the county. If a question arises regarding allowable expense deductions, refer to ARL Volume 3, Chapter 6, Real Property Valuation Manual and/or contact the county assessor.

• Who should file? - Any oil and gas producer and take-in-kind (TIK) royalty owner whose product has been transported from the premises to a point of sale downstream from the wellhead, including oil and/or natural gas, helium, and CO2 from oil and gas wells located in Colorado. This form is designed for assessors to compile, review, and verify netback deductions allowable under 39-7-101(1)(d), C.R.S., by operators and TIK owners. If you are unsure whether you should complete this form, contact the county assessor. If you have an actual wellhead sales price and/or are not taking any netback deductions from your downstream point of sale, you do not have to file this form.
• When should you file? - Under 39-7-101(2), C.R.S., you must file this form by April 15 or within 30 days of the postmark of the assessor’s written request, whichever comes last.
• What happens if you do not file? - For willful failure or refusal to comply, the assessor may apply a $100 per day penalty up to a total of $3000 and may also assign a Best Information Available (BIA) wellhead value based on sales of other oil and gas products within the field or other BIA calculation methods. Refer to 39-7-101(2) and 39-7-104, C.R.S., for further information.
• What happens after you submit this form? - The assessor will compile and statistically review the netback expenses deducted by all operators and TIK owners for oil and gas products sold during the preceding calendar year. If the assessor has additional questions or needs additional documentation of gross selling price or netback expenses, the assessor will notify you about the information needed, 39-5-115, C.R.S.

General Well Information

Please furnish the following information regarding the well:

• Well name and number. Please use the American Petroleum Institute (API) number as the well number.
• Total volume of product (oil, gas, CO2, helium, etc.) produced during the preceding calendar year
• Total volume of product (oil, gas, CO2, helium, etc.) sold or transported from the premises unsold for the preceding calendar year
• Volume-weighted average wellhead value of the product sold and at the downstream point of sale
• Actual point of sale

The volume-weighted sales price information must be the volume-weighted average downstream sales price of the product from which the netback expenses are deducted.

Unrelated Party Expenses

If you are claiming a netback deduction for fees or charges for wellsite processing, gathering, off-site processing, or transportation to the point of sale by an unrelated party, these charges must be listed here. You may be asked by the assessor to substantiate that these charges are actual expenses or have been properly allocated and that there is no relationship between you and the provider of the service. If the fee or charge for downstream services is "bundled" (more than one service cost included in the amount charged), include the total amount paid as a bundled cost deduction and note which downstream services are included in the fee or charge.

Related Party Expenses

Netback deductions claimed for services by parties related to the producer are subject to specific procedural criteria. "Related parties" are defined as individuals who are connected by blood or marriage; or partnerships; or businesses which are subsidiaries of the same parent company or are associated by one company controlling or holding ownership of the other company's stock or debt. For specific information on allowable related party deductions, refer to Chapter 6, ARL Volume 3, Real Property Valuation Manual published by the Division of Property Taxation. If you have claimed related party netback deductions, you must complete the Supplemental Information Report Form (SIRF) as well as this form. Contact the county assessor if you do not have a copy of the Supplemental Information Report Form.

Direct Operating Costs

Expenses for salaries, benefits, maintenance expenses, materials and supplies, equipment property taxes, insurance, payroll taxes, utilities, rental expenses, and other allocated direct general and administrative overhead costs by a related party should be listed here. Refer to Chapter 6, ARL 3 for a list of allowable and non-allowable operating costs.

Return on Investment (ROI)

Deductions for ROI for each downstream service provided by a related party must be listed here. Also, list the 2023 average investment balance for all equipment and improvement items still subject to depreciation and the ROI rate used to calculate the deduction. Refer to Chapter 6, ARL 3 for additional information regarding this deduction. For 2024, the allowable ROI threshold rate is 5.38% (published IG Corporate bond rate).

Return of Investment (RofI)

Deductions for RofI for downstream services provided by a related party must be listed here. Also, list the 1/01/2023 undepreciated investment balance for both equipment and improvement items that are still subject to depreciation, equipment and improvement lives, and/or your estimate of the remaining economic reserves used to calculate the deduction. Refer to Chapter 6, ARL 3 for additional information. Economic reserve estimate information need be submitted only if the units-of-production method is used.

2024 Supplemental Information Report Form

Supplemental Information Report Form (SIRF)

Taxpayer Instructions

Rev 1/24

This supplemental form is designed for reporting related party documentation and supplemental information regarding netback wellsite processing, gathering, off-site processing, and transportation expenses deducted by Colorado oil and gas producers to determine wellhead selling prices for property tax purposes. This form has been created for and must be completed pursuant to procedures under 39-7-101(1)(d), C.R.S. If a question arises regarding allowable expense deductions, refer to Assessors Reference Library (ARL) Volume 3, Chapter 6, Real Property Valuation Manual and contact the assessor.

• Who should file? - Any oil and gas producer and take-in-kind (TIK) royalty owner that has deducted netback wellsite processing, gathering, off-site processing, or transportation charges provided by a related party on the basic Oil and Gas Netback Expense Reporting Form, must file this form detailing the expenses deducted. If all netback expense charges listed on the basic Netback Expense Reporting Form are provided by unrelated parties, you do not have to complete this form. If you have not received a copy of the basic Netback Expense Reporting Form, contact the county assessor. "Related parties" are defined as individuals connected by blood or marriage; or partnerships; or businesses that are subsidiaries of the same parent company or are associated by one company controlling or holding ownership of the other company's stock or debt.
• When should you file? - Under 39-7-101(2), C.R.S., you must file this form as well as the basic Netback Expense Reporting Form, by April 15 or within 30 days of the postmark of the assessor’s written request, whichever comes last.
• What happens if you do not file? - For willful failure or refusal to comply, the assessor may apply a $100 per day penalty up to a total of $3000 and may also assign a Best Information Available (BIA) wellhead value based on sales of other oil and gas products within the field or utilize other BIA calculation methods. Refer to 39-7-101(2) and 39-7-104, C.R.S., for further information.
• What happens after you submit this form? - The assessor will review the supplemental information provided to ascertain that it complies with the allowable deductions and deduction calculation methods contained within ARL Volume 3, Chapter 6, Real Property Valuation Manual. Under 39-5-115, C.R.S., if the assessor has additional questions or needs additional documentation of gross selling price or netback expenses, the assessor will notify you regarding the information needed.

General Well Information

Please furnish the following information regarding the well.

• Well name and number. Please use the American Petroleum Institute (API) number as the well number.
• Total volume of product sold and/or transported during the preceding calendar year

This information must match the information reported on the basic Netback Expense Reporting Form that is filed as part of this return.

Listing of Netback Deductions

Itemize the direct operating expense deductions claimed for wellsite processing, gathering, off-site processing, or transportation to the point of sale. For specific information on allowable and non-allowable related party expense deductions, refer to ARL Volume 3, Chapter 6.

Listing and Computation of Return on Investment (ROI)

Please list the following information in the spaces provided for related party netback wellsite processing, gathering, off-site processing, and transportation expenses claimed. For 2024, the allowable ROI threshold rate is 5.38% (published IG Corporate bond rate)

• The remaining undepreciated plant investment balance as of 1/01/23
• The remaining undepreciated plant investment balance as of 12/31/23
• The average undepreciated investment balance determined by adding the 1/01/23 and 12/31/23 balances and dividing by two (2)
• The actual return on investment (ROI) for the listed operation component (up to the allowable published IG Corporate bond rate of 5.38% for 2024)

The ROI deduction is calculated by multiplying the average plant investment balance by the ROI rate listed. For specific information on allowable related party ROI deductions, refer to ARL Volume 3, Chapter 6.

Listing and Computation of Return of Investment (RofI) using Straight-Line Recapture

Please list the following information in the spaces provided for related party netback wellsite processing, gathering, off-site processing, and transportation expenses claimed.

• The remaining economic lives assigned by the company for the equipment and improvement items used in wellsite processing, gathering, off-site processing, or transportation operations
• The 1/01/23 remaining undepreciated investment balance determined for equipment
• The 1/01/23 remaining undepreciated investment balance determined for improvements

The annual RofI rate for equipment and improvements is calculated by dividing the number one (1) by the remaining economic life assigned for the asset by the company. The allowable RofI deduction is calculated by multiplying the 1/01/23 equipment and improvements remaining undepreciated investment balances by the annual RofI rate calculated above. For specific information on allowable related party RofI deductions, refer to ARL Volume 3, Chapter 6.

Listing and Computation of Return of Investment (RofI) using the Units-of-Production Method

Please list the following information in the spaces provided for related party netback wellsite processing, gathering, off-site processing, and transportation expenses claimed.

• The estimated remaining reserves. (Mcf or Bbl)
• The 1/01/23 remaining undepreciated plant investment balance.
• The percent of estimated remaining economic reserves produced during the preceding calendar year. If requested, you will need to provide the assessor with adequate documentation, such as Federal depletion allowance information, supporting your latest estimate of remaining economic recoverable reserves.

The RofI deduction is calculated by multiplying the 1/01/23 plant investment balance by the percentage of remaining economic reserves produced during the preceding calendar year. For specific information on allowable related party RofI deductions, refer to ARL Volume 3, Chapter 6.

Addendum 6-K, Coal Leaseholds & Lands Worksheet

Addendum 6-K, Coal Leaseholds & Lands Worksheet

Addendum 6-L, Earth & Stone Product Worksheet

Addendum 6-L, Earth & Stone Product Worksheet