Monthly Production and Cost Statement (MPCS) Submission Guide

Pertaining to the Frontier Lands Petroleum Royalty Regulations (FLPRR)

MPCS Submission Guide - PDF Version   (140 Kb, 16 Pages)

 


Table of Contents




This Guide

The guide was prepared by the Oil and Gas Management Directorate of Aboriginal Affairs and Northern Development Canada (AANDC) to provide general information to assist interest holders in completing their Monthly Production and Cost Statement (MPCS).

If you have further questions after reviewing this guide you can visit the INAC web site, or call an INAC representative at (819) 953-8790.






Royalty Management System (RMS)

The Royalty Management System (RMS) is an online electronic reporting application that is to be used by interest holders to submit all of their required royalty returns, including their MPCS.

For ease in using these guidelines to complete your filing, please note that the fields to be entered into RMS are highlighted in GREEN.

To use RMS, a company must register a user(s), have them complete training and install CITRIX Secure Connectivity on their workstation.  Find out more information about the RMS and/or how to become a registered user.






About the Monthly Production and Cost Statement Form

Purpose of the MPCS

The statement summarizes the petroleum volumes and costs associated with a production licence for the reporting month. Specifically, it sets out the:

  • Volumes of petroleum produced, consumed and transported from project lands;
  • Allocation of petroleum volumes to the interest holders in the production licence;
  • Allowed capital and operating costs, including costs associated with abandonment and restoration; and
  • Allocation of allowed capital and operating costs to the interest holders in the production licence.

The allocated production volumes and costs of a production licence flow through to each interest holder's Monthly Royalty Return, where they are used in computing the royalty payable for that month for the appropriate project.

A project is defined by the development plan, as approved by the National Energy Board. Royalty is payable by project, which may be composed of several production licences.

Requirement to File the MPCS

Who Must File

Where the production licence has only one interest holder, the MPCS is to be submitted by that interest holder. Where the production licence has more than one interest holder, the MPCS is to be submitted by the Representative.

The Representative

Where a production licence has more than one interest holder, the Canada Petroleum Resources Act  s. 9 requires that one party be nominated as the representative to act on behalf of all others for the purposes of the legislation and associated regulations. Please contact the Rights Administrator/Registrar for more information.

Filing Period

For each production licence, an MPCS needs to be filed for every month starting from either the month that:

  • The production licence was issued in, if the project commences in or before the month of production licence issuance; or
  • The month of project commencement, as included in the project's approved development plan, if the production licence is issued prior to the approval of a project development plan by the NEB.

The MPCS must be filed for every month thereafter for each production licence in a project, including months where there is no activity (i.e. a NIL return). An interest holder may cease filing a MPCS once the project is permanently "shut-in", but must continue to submit a MPCS during a temporary suspension in production in order to continue to track costs for future royalty calculations. Please see the definition of well termination for more information.

Filing Deadline

The MPCS must be filed on or before the 15th day of the second month following the month it is being filed in respect of.

Filing Month Filing Deadline
January 2008 March 15, 2008
February 2008 April 15, 2008
March 2008 May 15, 2008

Late Filing Penalty

Interest holders will be assessed a penalty of $1,000 for each month or part of a month that the MPCS has not been filed by the required filing deadline. An MPCS which is substantially incomplete, or contains data of inadequate quality, is also subject to the penalty.

Payment of penalties is due on the 15th of the month following the month in which they were imposed. Non-payment of an outstanding penalty or penalties will attract interest charges calculated from the day following the date payment was due until the actual date that payment is received by the Minister.






Header Information

Project Name The project name, or "Development Plan" identifier, is provided by the National Energy Board upon project approval. The entry of this field will be done automatically by RMS after the production licence is selected by the representative.
Production Licence The production licence identifier will appear in this field after the representative has picked it from the dropdown menu on the MPCS page.
Filed By The name of the company serving as representative, as it appears on the production licence, will appear here. This field is entered automatically by RMS. If your company name has changed please contact the Registrar at the Oil and gas Management Directorate.
Filed in respect of The reporting month and year to which the MPCS relates will be entered by RMS.
Production Month RMS will report the number of months that production has occurred in for the relevant project. During a pause in production, this number will remain static.
Version RMS will report whether the MPCS is the Original MPCS or an Amendment.
Was there production this month?

From the data entered in the forms, RMS will determine whether production occurred.

Were there costs this month?

From the data entered in the forms, RMS will determine whether costs were incurred.

Has production ceased?

The representative will identify whether production has permanently ceased. Note that temporary suspension of production does not terminate the obligation to file the MPCS for subsequent months.

If Yes, production cessation month If production has ceased, the representative will identify the month and year in which production permanently ceased.
Certified by The username of the individual who certified the MPCS submission and the date on which they submitted the form will automatically appear.





Petroleum Quantities Produced, Consumed or Transported

In this section the volume of produced petroleum is reported from the wellhead through to its disposition, which for oil is when it enters a transportation facility and for natural gas when it leaves a gas plant or, if processing is not required, when it enters a transportation facility.

All volumes are reported to one decimal place in their identified unit of measure.

Production (Line 20)

Natural gas and oil production volumes from the wellhead. This is the same data as reported to the National Energy Board on the NEB-WL (Well) Report.

Battery Adjustments (Lines 30 to 35)

Adjustments to wellhead production, as captured at the battery. These adjustments are the same quantities as reported to the National Energy Board on the NEB-BT (Battery) Report, Monthly Disposition Statement.

Fields to enter in RMS: lines 30-34

Gathering System Adjustments (Lines 50 to 55)

A gathering system is downstream of a battery and, for royalty purposes, is considered to be a transportation facility external to the boundaries of the project lands. Volumes entering a gathering system are by definition leaving project lands and, as such, are the volumes on which royalty is due subject to certain adjustments for flaring, gas used as compressor fuel, re-injected gas, and adjustments attributable strictly to metering differences. These adjustments are the same quantities as reported to the National Energy Board on the NEB-Monthly Statement of Gas Gathering.

Fields to enter in RMS: lines 50-54

Oil Available for Allocation (Line 70)

Oil volume to be allocated to interest holders and the volume on which royalty is payable (line 20 minus lines 35 and 55).

Gas Plant Inlet (Line 80)

Gas volume before gas plant adjustments (line 20 minus lines 35 and 55).

Gas Plant Adjustments (Line 90 to 101)

Natural gas volume adjustments that take place during processing at a gas plant including consumption of natural gas as plant fuel, flaring, metering differences, and shrinkage incurred in the production/stripping of gas products. These adjustments are the same quantities as reported to the National Energy Board on the NEB-Monthly Statement Gas Plant.

Fields to enter in RMS: lines 90-101

Gas Plant Outlet (Line 110)

Gas volume to be allocated to interest holders and the volume on which royalty is payable (line 80 minus line 102).






Petroleum Quantities Available for Allocation

Petroleum Quantities (Lines 120 to 121)

The petroleum and the residue gas and gas plant product volumes leaving a gas plant are reported using the appropriate unit of measure, as summarized in the following table. In the case of residue gas, the total energy content (GJs) is also reported.

Product Unit of Measure
OIL Cubic Metres (m³)
GAS LIQUID Cubic Metres (m³)
NATURAL GAS 1000s of cubic metres (10³m³)
SULPHUR Tonnes

Fields to enter in RMS: lines 120-121

Distribution of Petroleum Quantities (Lines 130 to 135)

The total petroleum volumes subject to royalty are reported. These are the volumes that are allocated to the interest holders. This includes volumes transported off of project lands and either sold (line 132), placed in storage (line 130), or injected into other formations (line 131).

Within line 133, volumes that are consumed, lost, or wasted and subject to royalty are reported. This applies to volumes both on and off project lands and includes situations where unnecessary loss of oil or gas volumes occurred, in the opinion of the National Energy Board, due to the:

  • Use of poor engineering and reservoir management practices;
  • Inefficient storage of oil or gas;
  • Escape or flaring of gas that could be economically recovered and processed or economically injected into an underground reservoir; and
  • Failure to use suitable recovery methods when those methods would result in increasing the quantity of oil or gas ultimately recoverable under sound engineering and economic principles.

Oil Available for Allocation (Line 134) is the sum of Line 130, 131, 132 and 133. This value reconciles with Line 70.

Gas Available for Allocation (Line 134) is the sum of Line 120 and 133.

Fields to enter in RMS: lines 130-133 and 135






Participation and Allocation of Petroleum Quantities by Interest Holder

Participation Percentage (Line 140)

The percentage of each petroleum product that is allocated or attributable to each of the interest holders is reported. The allocation percentages are to be computed to the eighth decimal and rounded to the seventh. The allocation percentages must add up to 100% for each of the petroleum products.

Field to enter in RMS: line 140

Volumes can only be allocated to interest holders who are registered as interest holders in the reporting month. Allocations cannot be made to former interest holders or interest holders in other production licences. If adjustments are required for previously reported volumes, they should be entered as amendments to the month in which the volumes were originally reported.

Allocation of Petroleum Quantities (Line 150)

The volumes of each petroleum product attributable to each of the interest holders are computed by multiplying the total volumes available for allocation (line 134) by the interest holder's participation percentage (line 140). These quantities are the volumes on which interest holders will pay royalty.






Allowed Project Costs

In this section the total allowed capital and operating costs for the month along with their allocation to each of the individual interest holders are reported.

Allowed capital and operating costs are defined in Schedule I Allowed Project Costs of the Frontier Lands Petroleum Royalty Regulations (FLPRR). Costs must meet all of the following criteria for them to qualify as either allowed capital or allowed operating costs (as defined in FLPRR sections 2 to 5):

  • They must be reasonably related to the production licence / project.
  • They are specifically provided for in the regulations. Costs not specifically provided for are not allowed costs.
  • They have been incurred, and have not been reimbursed in any way in whole or in part.
  • Where the costs are attributable to more than one project, those costs are to be allocated to each project on a reasonable basis.

Allowed Capital Costs (Lines 160 to 202)

In general, allowed capital costs can be grouped into the following four categories

  1. the drilling of wells on project lands,
  2. the building of an access road to or in preparing a site in respect of a well on project lands,
  3. the acquisition or construction of production infrastructure, and
  4. in respect of abandonment and restoration associated with the above activities.

The allowed capital costs are detailed below:

Allowed Capital Costs - FLPRR Schedule 1 s.1(1)

Allowed capital costs of a project are costs or expenses that are reasonably related to the project and that are:

  1. incurred in drilling or completing a discovery well, a delineation well or a development well located on the project lands;
  2. incurred in building an access road to, or preparing, a site in respect of a discovery well, a delineation well or a development well, where the well is located on the project lands;
  3. incurred, after the drilling of a discovery well, in respect of the collection in the field of basic geological, geophysical and geochemical information for the purpose of delineating the significant discovery indicated by the discovery well located on the project lands;
  4. a geological, geophysical or geochemical expense incurred in respect of logging, coring or testing conducted in the course of the drilling of a well referred to in paragraph (a);
  5. incurred in drilling or converting a well for:
    1. the disposal of waste liquids from a well located on the project lands,
    2. the injection of water, gas or any other substance into a petroleum formation to assist in the recovery of petroleum from another well located on the project lands, or
    3. the purposes of monitoring fluid levels, pressure changes or other phenomena in an accumulation of petroleum located on the project lands;
  6. incurred in drilling for water or gas on the project lands for injection into a petroleum formation located on the project lands;
  7. incurred in drilling or recompleting a petroleum well located on the project lands after the commencement of production from the well;
  8. incurred in respect of abandonment and restoration;
  9. incurred in acquiring or constructing production infrastructure that is to be located on the project lands or installing production infrastructure on the project lands;
  10. incurred in order to licence or purchase technology for the project, including any royalty or other cost paid in respect of letters patent;
  11. incurred in order to repair or maintain production infrastructure that is located on the project lands when the cost of those repairs or that maintenance is equal to or greater than 50% of the cost of equivalent new production infrastructure;
  12. incurred in conducting a study of some aspect of the project that is required by or under law before the project or the relevant part of the project is allowed to proceed; or
  13. expressly incurred as a cost under paragraph (i) or (k) but, for economic, environmental or logistical reasons, is for production infrastructure that is not located on project lands.

Classification of a well as a discovery well, delineation well, or a development well must be consistent with the reporting to the National Energy Board. Definitions of these terms and others, such as production infrastructure, are included in Appendix I.

Fields to enter in RMS: lines 160-162, 170-172, 180-182, 190-201 and 210.

Allowed Operating Costs (Lines 220 to 242)

In general, allowed operating costs are costs incurred in the day-to-day operation of production activities on project lands, including the operation of production infrastructure.

The allowed operating costs are detailed below:

Allowed Operating Costs - FLPRR Schedule 1 s.1(2)

Allowed operating costs of a project are costs or expenses, other than allowed capital costs, that are reasonably related to the project and that are:

  1. incurred on account of the salary, wages or other remuneration or related benefits of persons employed by the operator of production infrastructure that is located on the project lands;
  2. incurred
    1. in respect of the repair or maintenance of production infrastructure that is located on the project lands, where the cost of those repairs or that maintenance is less than 50% of the cost of equivalent new production infrastructure,
    2. on account of taxes in respect of production infrastructure that is located on the project lands, or
    3. on account of the rental or leasing of production infrastructure that is located on the project lands;
  3. incurred on account of premiums payable in respect of a policy of insurance, other than a policy of insurance for loss of revenue;
  4. incurred on account of
    1. the use of or the right to use any property located on the project lands,
    2. compensation for a service performed on the project lands,
    3. the acquisition of materials, parts or supplies for use on the project lands, or
    4. the transportation of supplies or personnel to or from the project lands;
  5. incurred on account of telecommunications, power, water or fuel used on the project lands;
  6. incurred on account of the disposal of waste materials, including sewage, from the project lands; or
  7. incurred on account of any production infrastructure whose cost is an allowed capital cost.

Fields to enter in RMS: lines 220-223, 230-241

Abandonment & Restoration Costs (Lines 250 to 255)

Abandonment and restoration costs are allowed capital costs that are reported and allocated to each interest holder separately. This provides interest holders who have established abandonment and restoration trusts to meet the reporting requirements of their Monthly Royalty Return (MRR).

The allowed abandonment and restoration costs are detailed below:

Allowed Abandonment & Restoration Costs (FLPRR s.2)

Abandonment and restoration means activities, in respect of wells, production infrastructure and geological, geophysical and geochemical operations that were allowed capital costs of the project, relating to

  1. the abandonment of a well,
  2. the destruction, scrapping, removal, disassembling and decommissioning of production infrastructure,
  3. the renewing, repairing, cleaning-up, remediation or other management of soil, water or sediment to the extent that the damage is consistent in scope and magnitude with any damage to the environment that would reasonably be expected where activities are conducted using good production practices so that the functions and qualities of the soil or water are comparable to those of its original, unaltered state, and
  4. the monitoring of the effectiveness of the activities referred to in paragraphs (a) to (c).

Fields to enter in RMS: lines 250-254

Allocation of Allowed Capital, Operating, and Abandonment & Restoration Costs ( Lines 210, 260 and 256)

The percentage of each allowed capital, operating, abandonment and restoration costs that is allocated or attributable to each of the interest holders is reported. The allocation percentages are to be computed to the eighth decimal and rounded to the seventh. The allocation percentages must add up to 100%. The amount of each cost that is allocated to the interest holders is computed automatically by RMS.

Costs can only be allocated to interest holders who are registered as interest holders in the reporting month. Allocations cannot be made to former interest holders or interest holders in other production licences. If adjustments are required for previously reported costs, they should be entered as amendments to the month in which the costs were originally repoorted.

Fields to enter in RMS: lines 210, 260 and 256

Costs Not Allowed as Either Allowed Capital or Operating Costs - FLPRR Schedule 1 s.2

The following are not allowed capital or operating costs of a project:

  • the part of a cost that is subject to reimbursement, whatever the source;
  • an amount on account of interest, including an amount or taxes expenses as described in paragraph 20(1)(c), (d) or (e) of the Income Tax Act, as amended from time to time;
  • a cost or expense in respect of the administration, management, overhead or financing of an interest holder or of the operator of production infrastructure;
  • the administrative costs of an abandonment and restoration trust,
  • a payment to a person who does not deal at arm's length with the interest holder making the payment, to the extent that the payment exceeds the fair market value of the property, the use of the property, the right to use the property or the performance of a service in respect of which the payment is made;
  • a payment on account of an overriding royalty, a net profits interest, a carried interest or other similar interest;
  • a cost or expense resulting from any act or omission that constitutes a breach of any federal, provincial or municipal law; and
  • a cost or expense in respect of processing petroleum other than a cost or expense in respect of producing transportable petroleum;
  • a cost or expense in respect of the transportation of petroleum produced from the project lands to a point beyond the boundary of the project lands, unless it is for production infrastructure that is not located on project lands in accordance with paragraph 1(1)(m);
  • an allowed capital cost or allowed operating cost, respectively, of another project, unless it was allocated with section 3;
  • a tax imposed under Part IX of the Excise Tax Act, as amended from time to time; and
  • a cost or expense that is not expressly provided for in section 1.

Proceeds from the Sale, Leasing, Licensing of Assets or from Insurance

Where such proceeds are received in a month in respect of a cost that was previously included as an allowed capital or operating cost of a previous month, the proceeds are included as reduction to either allowed capital or operating costs, as appropriate, in the month in which they are received.

Proceeds include an entitlement to receive an amount under a policy of insurance for loss or damage to property and amounts from the licensing or from the sale, lease or other disposition or use of any tangible or intangible asset.

The proceeds are to be reported on line 201, if they relate to a previously allowed capital cost and on line 241, if they relate to a previously allowed operating cost. In each case, the source of the proceeds must be specified.

If the proceeds exceed the total allowed capital or operating costs in the month that they are received the difference will be calculated as either a negative total allowed capital or operating cost on lines 202 or 242, respectively.

Proceeds from loss of revenue insurance are not to be reported. Premiums paid for loss of revenue insurance are not allowed costs and as such any proceeds from the insurance are also excluded.






Appendix I

Interpretation of Key Terminology

Definitions are compiled from the FLPRR and CPRA

TERM DESCRIPTION
Delineation Well "delineation well" means a well that is so located in relation to another well penetrating an accumulation of petroleum that there is a reasonable expectation that another portion of the accumulation will be penetrated by the first-mentioned well and that the drilling of the first-mentioned well is necessary in order to determine the commercial value of the accumulation. FLPRR s.2, Interpretation.
Development Well "development well" means a well that is so located in relation to another well penetrating an accumulation of petroleum that it is considered to be a well or part of a well drilled for the purpose of production or observation or for the injection or disposal of fluid into or from the accumulation. FLPRR s.2, Interpretation.
Discovery Well "discovery well" means the well drilled on a geological feature that indicates that a significant discovery has been made. FLPRR s.2, Interpretation.
Exploratory Well "exploratory well" means a well drilled on a geological feature on which a significant discovery has not been made. FLPRR s.2, Interpretation.
Gas Plant means a facility for processing transportable petroleum by any process, including absorption, adsorption and refrigeration, designed to recover residue gas or gas plant products. FLPRR s.2, Interpretation.
Interest holder Interest holder means, in respect of an interest or a share therein, the person indicated, in the register maintained pursuant to Part VIII (CPRA), as the holder of the interest or the share. Interest means any former exploration agreement, former lease, former permit, former special renewal permit, exploration licence, production licence or significant discovery licence. CPRA s.2, Interpretation.
Production Infrastructure "production infrastructure" means any equipment and buildings that are used for the production or treatment of petroleum from the reservoir and includes (a) equipment for natural pressure reduction, mechanical separation, heating, cooling, dehydration and compression, and (b) batteries, gathering lines, storage areas, tanks, landing areas, heliports and personnel accommodations. FLPRR s.2, Interpretation.
Transportation Facility "transportation facility" means a pipeline, tanker or other transportation equipment used to deliver petroleum from project lands, or in the case described in paragraph 1(1)(m) of Schedule I (where production infrastructure is not on production lands), from production infrastructure, to the point at which the petroleum is delivered to the first purchaser of the petroleum. FLPRR s.2, Interpretation.
Well Termination "well termination" means a well or test hole has been abandoned, completed or suspended in accordance with any applicable regulations respecting the drilling for petroleum made under the Canada Oil and Gas Operations Act.