Frequently Asked Questions
The Petroleum Accountants Society of Canada (PASC) does not assume any liability for the use or reliance upon any statements, whether oral or written or any procedure or publication (collectively, the “Forms”) or any variation thereof. Any use or reliance upon the Forms shall be at the sole discretion and risk of the user party and such user party agrees by the use of any of the Forms to release and hold PASC harmless from any or all harm. PASC further assumes no responsibility concerning the utility or operation of all or any part of the Forms, including but not limited to, any person’s or corporation’s particular requirements, and assumes no responsibility for any harm, losses and liabilities suffered, sustained and incurred, regardless of how they may have been occasioned, from the use of misuse of all or any part of the Forms. PASC responds to questions from time to time and any answer given is based solely on the amount of detail provided in the original question. PASC makes no warranty, expressed or implied, whether in fact or in law with respect to the Forms and to any response provided herein.
*Please note that we cannot accept a question which pertains to an ongoing dispute
Area Allocations – examples of Costs Centers to include
What type of cost centers (i.e. well cost centers, battery cost centers, compressor cost centers) can be included in an area allocation? The PASC accounting procedure(s) does not indicate what can be included.Show response
In general, all accounting procedures (“AP”) define Joint Property, Joint Account and Joint Operations in a manner similar to the 2011 PASC Accounting Procedure (“PASC2011”). Below are the PASC2011 definitions:
Joint Account means the account showing, in Canadian funds, the charges paid and credits received as a result of Joint Operations and which are to be shared by the Parties in accordance with the terms of the Agreement.
Joint Operations means those operations and activities undertaken pursuant to terms of the Agreement and are for the Joint Account.
Joint Property means all property subject to the Agreement and maintained for the Joint Account. Therefore, a Joint Property can consist of wells, facilities and pipelines.
Article II of all APs outlines all items that may be charged to the Joint Account. Where possible, services and Materials should be charged directly to the well, facility or pipeline that gave rise to the expense. However, there will be expenses that cannot be directly attributed to any one well, facility or pipeline or the expense is incurred on behalf of multiple Joint Properties. In these instances, the Operator may allocate the item to the Joint Account(s) in an equitable manner. All APs address apportioning of expenses on an equitable basis if an item cannot be directly charged to a specific cost center. Clauses 109(H) and 109(I) of PASC2011 outline the equitable allocation of costs between the Joint Property, Administration (as defined in PASC2011) and areas that are solely for the Operator’s account.
At this point it is up to the Operator to determine how to equitability allocate an item to multiple cost centers. The Operator should be able to support its expense allocation through its historical accounting records and practices, time sheets or other relevant information.
Therefore, an area allocation could include well, facility and pipeline cost centers from one Joint Property or the area allocation could include well, facility and pipeline cost centers from multiple Joint Properties. It is incumbent on the Operator to be able to support the equitable allocation of charges between the various cost centers.
Area allocations should be reviewed on a regular basis to ensure the allocation of charges is still equitable. For example, a producing well and a suspended well should not be part of the same area allocation as a suspended well would not incur many of the expenses that a producing well would incur (i.e. production chemicals). As a result, it may be necessary to add and remove costs centers from the area allocation from time to time.Hide response
Emergency Procedures & Safety Manuals – allowable Joint Account Charges
We incur costs for our Corporate Emergency Response Plan, which is required for the operator to produce at its various locations. Our partner is refusing to pay its portion of these costs claiming that it is not “site specific”, pursuant to clause 217(e). Again this provision appears very punitive for the operator as all operators must have a Corporate Emergency Response Plan or else it cannot produce from its properties on behalf of its partners. We should be entitled to charge our partners for these costs in a reasonable manner as it is required to operate the property. Unless the term “safety manuals” in clause 217(e) is intended to refer to the costs of the Corporate ERP, in my opinion all safety work is an operating expense as it is a requirement to operate our properties. Please provide comments.
Clause 217(e) of the 1996 Accounting Procedure (“PASC1996”) limits the charging of any emergence response plan (“ERP”) to an ERP that is specifically for the Joint Property. For further clarification, the Explanatory Text (which is part of PASC96) states:
“General emergency manuals that are NOT site specific are not chargeable.”
The Operator is compensated for its general costs through the Overhead recovery provisions in Article III of PASC96. Subclause 301(b) states:
“Overhead means all costs to the Operator other than those costs pursuant to Article II of this Accounting Procedure”
Corporate ERPs, by their nature, are general emergency manuals and therefore are not chargeable to the Joint Account and are considered to be costs recovered under the Overhead provisions. This concept applies to all safety costs. Unless the safety cost is specific to the Joint Property, that cost is considered to be part of the Overhead recovery mechanisms of PASC1996.
The Operator can seek approval of the Owners to amend the Overhead rates if the Operator believes that the rates amounts do not adequately compensate the Operator for its portion of general costs incurred on behalf of the Joint Operations. Alternatively, the Operator can seek approval of the Owners under Clause 110 to charge a portion of its Corporate ERP to the Joint Account under Clause 220 – Other Costs.
It should be noted that the 2011 Accounting Procedure (“PASC2011”) contains similar provisions to PASC1996. Under PASC2011, ERPs must be site specific to be charged to the Joint Account and general ERPs would be costs recovered under the Overhead provisions.
I understand the response and I see the provisions in the accounting procedure, but I don’t agree. Pursuant to government regulations operators must have corporate safety procedures in place to operate. As such, the joint operation certainly benefits. In my opinion this is definitely an operating cost, which can be significant as these safety manuals are large accumulations of materials and information which require significant attention and ongoing maintenance from a 3rd party in our case. The overhead recovery provisions are not significant enough to cover these costs and our partners would never be willing to increase the relatively low overhead fees or a charge pursuant to Clause 110. For clarification, our safety manuals are obviously distributed to all field operators and while the binder is called the Corporate Emergency Response Plan and contains emergency duties and responsibilities, communication plans, response action plans and post emergency items; it also includes site specific information such as specific contact information (including gov’t agencies, emergency services, industry support services, spill support services), locations of all wells, pipelines, facilities, storage tanks, highways, area roads, railways, creeks and rivers and detailed maps in each specific area. I would argue these manuals do include very specific site information so in my opinion these are not general emergency manuals. Obviously you do not know what our manual looks like, but considering it includes site specific information distributed to the field operators and to the appropriate head office individuals, is it reasonable to charge the joint account for these manuals.
With the additional information that the corporate manual contains specific site information and are distributed to each field operating centre, then a portion of the cost may be distributable to each operation to which the manual relates. That said, the manual would need to contain enough specific information that each field operating centre does not have to prepare any additional documentation or supplemental manual for its site-specific ERP.Hide response
Engineering and Design Charges to the Joint Account
Please provide the purpose for this clause which limits the amount that can be charged to the joint account to the approved project estimate plus the greater of $2,000 or 10%. Correct me if I am wrong, but I do not believe this provision exists in the 2011 PASC Accounting Procedures. If I am correct, why was that Engineering and Design provision removed from the 2011 PASC Accounting Procedures? Obviously there are several costs incurred in a drilling, completion, equipping or construction process which can be higher or lower than the approved estimates for that particular cost, but it appears only the engineering and design charges are limited to additional charges pursuant to 205(b)(1). Typical industry practice is that supplemental AFEs are provided to the joint venture partners if the total cost of the project is >10% of the total approved estimate, but an operator would not typically obtain specific approval if the engineering and design charge is over the AFE budgeted amount for that specific cost. This provision appears very punitive for the operator as there can be several issues that occur in a specific operation that can cause Engineering and Design to exceed the approved amount by more than $2,000 or 10%. Please provide comments to help me understand the purpose of this provision in the 1996 PASC Accounting Procedures.
Your explanation of typical industry practice follows the intent of this clause, which is to allow a maximum variance between the total amount of the AFE estimate and total actual cost without triggering a supplement. This allows the Operator to charge for actual engineering and design, within the limits set out in the approved document or as amended and agreed to by the Owners. Without such a limitation for projects where the E&D charges are calculated as a percentage of total AFE costs, the charges for E&D could increase substantially merely by the operation exceeding its AFE limit without any additional engineering involved; such as being stuck in the hole or contract charges/excess charges for a wet location. If the Operator requires additional funding for E&D, they will need to get partner approval and if the Operator is charging by timesheet, this should not be difficult to substantiate.
This limitation on the variance between estimated and actual was first introduced in the 1988 Accounting Procedure shortly after the release of the 1987 PJVA Operator Cost Recovery Report that recommended various methods for Operators to recover Engineering and/or Design costs on joint operations. Industry could not collectively agree on how engineering and/or design costs should be charged (i.e. actual cost, time sheets, allocations, a percentage of cost, sliding scale rate) or any associated ceilings, and there was a concern that larger companies with large internal engineering staff would pass on significant costs to their partners. The limitation was implemented to help manage this. With the 1996 Accounting Procedure, the limitation on the variance between estimated and actual E&D costs was continued due to the introduction of off-site engineering and for the same reason - to provide the non-operator the opportunity to evaluate and have some say in engineering costs associated with a given project.
In the PASC 2011 Accounting Procedure, the engineering and design charges were moved under Clause 201(H) and different criteria for charges was used wherein there is a list of engineering activities allowed for approved projects. An estimate for E&D is still required; however, the limitation applies only where a percentage basis or some other form of rate (e.g. lump sum, percentage of project cost, etc) is used. The only limitations imposed within the 2011 Accounting Procedure are within clause 111: an explanation if the total project cost exceeded the estimated total project cost in the AFE/approval document is required or the need for a revised AFE if there's a scope change.
For furthering information on this topic, PASC has the following publications available:
- API-08: PASC 1988 Accounting Procedure Interpretation
- GP-14: Overview of the 2011 PASC Accounting Procedure
- API-15: Chargeable Engineering Activities Under the 2011 Accounting Procedure
The 1996 Accounting Procedure incorporates its companion Explanatory Text as part of the Accounting Procedure. The 1987 PJVA Operator Cost Recovery Report is available through the Petroleum Joint Venture Association.
In our AFEs we charge an internal engineering & design fee of 2% (to estimate internal employee charges) of the total AFE amount which was agreed to with our partners and we never charge more than the budget amount. In other words, if the AFE was overspent we did not increase this internal charge. The issue I am having is that we also use outside third party engineering firms as advisors, which along with our internal staff will ensure the operation is executed properly. Obviously these 3rd party invoices can go over budget like any other line item expenditure on an AFE. I don’t understand why this 3rd party charge as defined in 205(a)(2) is limited to 10% or $2,000 pursuant to 205(b)(1) while no other AFE sub-feature for third party charges have this limitation. Our partner is asking for a reimbursement of these excess charges from our 3rd party engineering advisors, which is a significant burden for the operator to bare for the joint operation. I do understand the limitation for an internal charge based on the % of the AFE, but a third party charge is a third party charge and should be shared with the partners if it is legitimate. Our partner is using the specific wording of the 1996 accounting procedures in 205, but I don’t believe that is an equitable or fair resolution for the operator. It appears 2011 procedures have totally removed that limitation for 3rd party charges which is reasonable in my opinion. The limitation must have been removed from 2011 as it was determined this provision may create an incorrect result.
The 1996 PASC Accounting Procedure outlines the chargeability criteria and associated limitations for engineering and design costs in Clause 205. Both third party engineering costs and Operator’s in-house engineering costs are allowable charges to the Joint Account subject to Clause 205.
The provisions of the 2011 PASC Accounting Procedure and associated APIs have no bearing on allowable charges to the Joint Account unless it is attached to and forms part of the governing agreement.Hide response
Engineering and Design – percentage based charges
Would it be possible to obtain some guidance on the percentage figure for the in-house engineering costs charged to AFE? We’d like to set it up in the system in such way that, preferably, all AFE's are charged uniformly, based on some average in-house engineering percentage rate. Does such "average rate" exist?
Supposedly, for the past few years, most companies have adopted the approach of charging flat percentage on the total AFE costs (less admin charges) as it’s much easier to administer. As the industry is going away from the timesheet approach and adopting the flat percentage based methodology, there seems to be a wide discrepancy of the percentage number that is perceived as reasonable.
I've talked to few auditors representing different companies and heard that, on average, the charge is between 2% and 4%. Looks like the decision what percentage number is being used "across the board" depends on whether the company is normally using third party engineering and in-house engineering resources (the percentage charged is lower, ie. 2.5% "across the board") or strictly in-house engineering resources are used (the percentage is higher then, up to 4%).
Would you agree with the above statement? Is there such thing as "industry standard rate"?Show response
Unfortunately there isn't an industry standard rate for charging out engineering costs on a percentage basis. Initially you will need to verify if the accounting procedure for the joint operation even allows for a percentage rate to be charged for in-house engineering. Not all accounting procedures make provisions for percentage rates to be used. Having said that, most accounting procedures will allow the Operator to charge “non-standard” items to the joint account where the Operator has received prior approval from the partners to do so. Therefore, the Operator could use a percentage rate to charge out in-house engineering to an AFE if the Operator specifically outlined rate and estimated amount on the AFE.
As indicated in your question, the percentage rates can vary between companies and within a company the percentage rate can vary depending on whether only in-house engineering is used or if in-house engineering is used in conjunction with third party engineering services. Typically, the third party engineering time would be direct charged to an AFE. Percentage rates should be based on the individual operator’s cost history which is why there appears to be a range of rates being used by industry.
An operator should consider several factors when establishing a percentage rate for charging out in-house engineering. Firstly, use of a percentage rate needs to be equitable to partners, in that the rate is strictly a cost recovery mechanism. The percentage rate should equate to the Operator’s actual cost of salaries, wages and employee benefits for chargeable engineering functions and should not include costs of any administrative functions. Secondly, an Operator may have different rates for different projects (i.e. the in-house engineering rate for a drilling project may be different than the rate for a facility construction project) and different rates if both in-house engineering and third party engineering services are used for a project.
In summary, each Operator needs to establish its own percentage rates, based on its cost history. The Operator may require partner approval to use those percentage rates if the accounting procedure in question does not make allowances for charging out engineering services on a percentage basis.Hide response
Orphan Well Levy – chargeable to the Joint Account
Is the Alberta Orphan Fund Levy chargeable to the Joint Account?Show response
The Alberta Orphan Fund Levy (the “Levy”) is invoiced semi-annually to the well or facility licensee by the AER. The Levy invoice is determined based on the well and facility licenses held in the Operator’s name. The AER assigns a deemed liability to each license and the Levy is determined based on that deemed liability. The detailed listing of the licenses and assigned liabilities are available to the Operator through the AER’s Digital Data Submission (“DDS”) system.
Under Accounting Procedures prior to the 2011 Accounting Procedure, the Levy is a regulatory requirement relating to ecology or environment of the Joint Property and therefore would be an allowable charge under the Ecological and Environmental Clause of that Accounting Procedure. The Levy is an allowable charge under Clause 210 – Taxes, Fees and Levies of the 2011 Accounting Procedure.
Any similar levies invoiced to a well licensee or facility operator by a Government agency, such as the annual AER administration fee, would also be chargeable provided that sufficient detail is available to charge a portion of the levy to the Joint Account.Hide response
Road Use Agreement – Credits to the Joint Account
I am the Operator in a JOA with a 90 CAPL and a 96AP and a third party drilled wells close to ours and instead of building lease roads have entering into road use agreements with us for the portions of roads they use. We have billed the third party for and initial consideration of $1000 and a road use of $3000 per year. I credited the $3000 back to the initial road ownership. My question is: how does industry credit this additional $1000 consideration fee.
The initial consideration is not an administration fee but an upfront payment to access the location. The Operator negotiated a surface lease with a land owner to drill wells and build pipeline/access road. This surface lease would include a payment for an initial consideration plus the initial year's rental. As the operator would charge the joint account for that initial consideration, it should also credit the Joint Account for an initial consideration it receives on the same surface lease.Hide response
Shut-in wells – allowable Operating and Maintenance costs
As operator we have internally elected to continue to allocate 1st line supervisor and field expenses to wells that are shut-in, as we are required to inspect, maintain and report these wells. Our policy presently is to terminate the allocations if and when a well is suspended.
Our partners are disputing these costs and short paying their invoices based on “industry practice” arguments.
There doesn’t appear to be reference in any PASC Accounting Procedure on this issue. Is there any specific guidance on this topic?Show response
For the purposes of this Q&A, the well is assumed to be in Alberta; however, it would appropriate to apply this answer to wells in both British Columbia and Saskatchewan.
Wells may be shut-in for a variety of reasons, such as waiting on well servicing to restore production, conversion of the well for another purpose (e.g. converting a producing well to a water injector) or the well may be shut-in for more “permanent” reasons such as the well no longer being capable of production or if the well is capable of production, it is no longer economically viable. Operators are required to report production activity for a shut-in well to the AER, even though production is nil.
Under AER Directive 013: Suspension Requirements for Wells, well suspensions are automatically required for wells that have been shut-in for 6 or 12 consecutive months, depending on the type of well. As a result, no well can remain in a shut-in state indefinitely. After the well has been suspended, the Operator is required to monitor the well on a regular basis (once a year to once every five years, depending on how the well was suspended), ensure security of the wellhead and perform regular wellhead servicing.
From an operations standpoint the field work required to operate a well that is “permanently” shut-in or formally suspended is similar. Ongoing work includes, but is not limited to, well site and access road maintenance, well pressure testing and repairs and maintenance of the wellbore and wellhead. However, it should be noted that work on a “permanently” shut-in or suspended is typically performed on a periodic basis and not on a regular monthly basis as is work on a producing well.
Ongoing Expenses Related to “Permanently” Shut-in and Suspended Wells
As indicated above, the Operator is required to monitor the well on a regular basis, ensure security of the wellhead and perform regular wellhead servicing. As a result, the Operator will incur ongoing, but not regular, expenditures related to a “permanently” shut-in or suspended well. Ongoing expenditures may include, but are not limited to, lease and road maintenance, road use charges, property taxes, regulator levies, required pressure testing and repairs and maintenance of the wellhead.
In some instances, wells that are tied into a third party facility are required to be operated by the operator of that facility. Consequently, the well Operator may have been required to enter into a contract operating agreement with the third party operator. Under a contract operating agreement, it is typical for the monthly production administration portion of the contract operating fee to apply even if a well is in a shut-in state. The production administration fee is typically eliminated when the well is suspended. Depending on the agreement, the operating portion of the contract operating fee may be eliminated or reduced once the well is shut-in and entirely eliminated when the well is suspended.
Under the majority of PASC Accounting Procedures, the Operator is not allowed to charge any fixed rate Producing Well Overhead once a well has been shut-in for greater than three (3) consecutive months. The Operator is allowed to charge a percentage rate Overhead for ongoing expenses related to a shut-in/suspended well if the Accounting Procedure allows for the percentage rate Overhead. Please consult the specific Accounting Procedure related to the Joint Operation for the treatment of overhead for shut-in or suspended wells.
Equitable Allocation of Operating Expenses
PASC Accounting Procedures from 1988 and forward contemplate the “equitable allocation” of expenses where it is not feasible or practical to directly charge expenses to a well. Although the phrase “equitable allocation” is not used in older Accounting Procedures, industry has generally accepted and allowed allocations in those older agreements.
The key word for cost allocation is “equitable”. The Operator has to demonstrate a well is being allocated its proportionate share of appropriate charges. For example, it would not be appropriate to allocate costs related to production chemicals to a “permanently” shut-in or suspended well as these wells are not on production. However, it would be appropriate to allocate costs related to weed control to a “permanently” shut-in or suspended well as all well sites must be maintained.
In general, PASC Accounting Procedures indirectly address the idea that “permanently” shut-in and suspended wells do not incur expenses on the same “equitable” basis as producing wells by disallowing the fixed rate Producing Well Overhead once a well has been shut-in for greater than three (3) consecutive months. Please consult the specific Accounting Procedure related to the Joint Operation for the definition of shut-in or suspended wells
Recommendation for Appropriate Operating Expenses for a “Permanently” Shut-in Well
It is understood that operating and maintenance expenses are incurred for all wells, whether they are producing, shut-in or suspended. However, as indicated above, “permanently” shut-in and suspended wells do not incur expenses on the same regular basis as do producing wells.
In general, for the Accounting Procedure purposes, a “permanently” shut-in well should be considered to be any well shut-in for greater than three (3) consecutive months. Please consult the specific Accounting Procedure related to the Joint Operation for the definition of shut-in or suspended wells.
Ideally, it is recommended that all operating and maintenance expenses be direct charged to a “permanently” shut-in or suspended well. This process should ensure disputes between the Operator and the Non-Operator are eliminated or reduced.
It is recommended that the Operator remove “permanently” shut-in or suspended wells from any monthly cost allocation that it is using for producing wells as that allocation is no longer “equitable” for the shut-in or suspended wells. In joint operations where there are numerous shut-in and suspended wells, and it is not feasible or practical to direct charge expenses to those wells, the Operator may set up a separate “equitable” allocation for those shut-in and suspended wells. It is then incumbent on the Operator to ensure that costs related to the production of hydrocarbons are not charged to the shut-in/suspended well allocation. The Operator may need to initially demonstrate that the new shut-in/suspended well allocation is in fact equitable.
From a partner standpoint, the Non-Operator should not dispute allocated charges to a well that is shut-in for three (3) consecutive months or less. The Non-Operator should also not dispute charges to a shut-in well where an Operator has set-up a separate equitable cost allocation for “permanently” shut-in and suspended wells.Hide response
Shut-in wells –allowable operation & maintenance/wells shut-in for years
We have a situation where several gas wells have been shut in for more than a few years. This is due mainly to price per GJ. What charges would be considered acceptable besides property taxes, ERCB fees, surface/mineral lease rentals? The operator is charging a contract operator, vehicle costs and road usage charges. Would these be acceptable for a well that has been shut in for more than three years?
Regardless of the wells being shut-in, certain operational and regulatory activities may still be needed.
As to contract operating arrangements, it's difficult to tell from your question whether you're referring to contract labour hired by the Well Operator, or contract operating charges incurred by the Well Operator under a contract operating arrangement with a downstream Facility Operator.
Scenario 1: Costs under a formal Contract Well Operating Agreement (CWOA) between the Well Operator and another Operator:
Most Contract Operating agreements are structured so the Contract Operator charges the Well Operator a fee for physically operating the well and a fee for administration (production accounting and Board Reporting):
a) Operating Fee:
For shut-in wells (whether shut-in for months or years), the CWOA should provide direction as to whether a fee is chargeable by the Contract Operator to the Well Operator. Quite often parties establish a reduced operating fee (e.g. $300/well/month as opposed to $1,000/well/month while producing). Some agreements do not have a two-tiered fee resulting in the singular fee applying until such time as the well status is changed with the Regulators or the CWOA is terminated.
b) Admin Fee:
For shut-in wells, Board Reporting continues until the well status is formally changed. As the Contract Operator would continue to be responsible to report the well to the ERCB until such time as well status is formally changed or the CWOA is terminated, a monthly Admin Fee is chargeable to and payable by the Well Operator. The same applies to well reporting within BC and SK. Note that as with the operating fee, parties often negotiate a reduced rate for non-producing wells.
c) Other Costs:
Any other costs permitted by the CWOA (e.g. lease maintenance, weed control, periodic checking for wellhead and pipeline integrity, vent leaks and vandalism, etc) would also be billed to the Well Operator. Presumably, use of the road would be required to access the wellsite, resulting in road fees if under a fee-for-access arrangement with another party.
Costs billed to the Well Operator that are chargeable to the well partners, would be as provided for in the Accounting Procedure attached to the JOA or other head agreement.
Note that there are variations in Contract Well Operating Agreements used within industry, especially if entered into prior to the PJVA Models being created. The 1995 and 2003 versions of the PJVA model have different provisions: the 1995 version indicates that once the appropriate paperwork is filed with the Regulatory groups, and notice is provided to the Contract Operator, no fees are payable while the 2003 version does not expressly provide for this, however if it is negotiated, the Task Force recommended it be placed on Exhibit "B" (fees).
Scenario 2: Contract labour engaged by the Well Operator.
Labour and vehicle costs would be expected for routine inspection and maintenance of the well, wellsite and pipeline as outlined above, and for use of the access road.
In both scenarios, the above costs would be in addition to the fixed costs of property tax and lease rentals, etc.
There may be options for reducing ongoing maintenance costs, however this would entail a discussion between your Operations staff and the Well Operator's staff to understand what ongoing maintenance is needed vs being performed.
Well suspension costs – allowable charges to Joint Account
How should well suspension costs be charged to the Joint Account?Show response
For the purposes of this Q&A, the well is assumed to be in Alberta. Both British Columbia and Saskatchewan follow similar protocol for the suspension of wells.
Well Suspension Background
A company typically suspends a well because it is not economically viable, but could be in the future, should new technologies and infrastructure be developed or commodity prices improve. In addition to economic considerations, in Alberta, the Alberta Energy Regulator (“AER”) requires an Operator to automatically suspend a well that has been shut-in for 6 or 12 consecutive months, depending on the type of well.
The AER considers a well suspended when it meets the requirements set out in Directive 013: Suspension Requirements for Wells. To suspend a well, an Operator must notify the AER and must perform a series of procedures to ensure the well is safe to the environment and public while it is inactive. For low-risk wells, suspension work may only consist of inspecting and pressure testing the well. Low-risk wells that remain suspended for 10 consecutive years must then be suspended in accordance with the requirements for medium-risk wells. For medium-risk and high-risk wells, suspension work can range from placing a downhole packer and tubing plug in the well to pulling all downhole equipment and setting a bridge plug topped with eight meters of lineal cement.
In all cases, after the well has been suspended, the Operator is required to monitor the well on a regular basis (once a year to once every five years, depending on how the well was suspended), ensure security of the wellhead and perform regular wellhead servicing.
Charges to the Joint Account
Well suspensions are specially identified part of Drilling activities under PASC 2011 Subclause 301(E)(7). While not specifically mentioned in PASC 1996 and PASC 1983, well suspensions would also fall under the Drilling definition as only routine cleanouts and pump or rod pulling operations are excluded from the definition. As a result of the inclusion of well suspensions under Drilling activities, the Operator would consider the suspension operation as a separate project and the project would then qualify for Drilling Overhead at the rate allowed under the governing Accounting Procedure.
Whether or not the Operator or Non-Operator chooses to capitalize or expense the suspension operation will depend on each company’s accounting policies. However, the Operator will need to specifically identify the suspension operation in its joint interest billing to the Non-Operators. The Operator can accomplish this through raising an AFE to suspend the well, or using a separate range of accounts specific to well suspensions.
Suspensions Requiring an AFE
An AFE must be raised if the cost of a suspension operation exceeds the approval threshold specified under the Accounting Procedure. Even if the suspension costs are under the Accounting Procedure expenditure approval threshold, utilizing an AFE may allow for easy identification of the suspension operation, plus using an AFE enables the Operator to use its accounting system to properly charge overhead to the project.
An AFE that exceeds the expenditure threshold limit under the Accounting Procedure, may not require Non-Operator approval if the suspension is required under the Regulations in a particular jurisdiction. In Alberta, well suspensions are automatically required for wells that have been shut-in for 6 or 12 consecutive months, depending on the type of well. Even if Non-Operator approval is not required, the Operator is still required to promptly advise the Non-Operators of such expenditures.
Ongoing Expenses Related to Suspended Wells
As indicated above, once the well is suspended, the Operator is required monitor to the well on a regular basis, ensure security of the wellhead and perform regular wellhead servicing. As a result, the Operator will incur ongoing, but not regular, expenditures related to a suspended well. Ongoing expenditures may include, but are not limited to, lease and road maintenance, property taxes, regulator levies, required pressure testing and repairs and maintenance of the wellhead. These ongoing charges should be considered as operation and maintenance expenses.
Since ongoing expenditures are usually not incurred monthly, it is recommended that the Operator remove the suspended well from any monthly cost allocation that it is using for other producing and shut-in wells in the area. In instances where a well was contract operated by a third party under a contract operating agreement, the suspension of the well usually results in a decrease or termination of the contract operating fee and the production administration fee that the contract operator charges to the Operator. The Operator should ensure it reviews its ongoing obligations under the contract operating agreement when it suspends a well.
- As indicated above under “Charges to the Joint Account”, the operation to suspend the well would attract the Drilling Overhead rate allowed under the governing Accounting Procedure.
- For Operations and Maintenance purposes, the Operator would not be allowed to charge any fixed rate Producing Well Overhead. A suspended well has typically been shut-in for greater than three (3) consecutive months and, therefore, the well no longer is considered a Producing Well for fixed rate overhead purposes. The Operator would be allowed to charge a percentage rate Overhead for ongoing expenses related to a suspended well if the Accounting Procedure allows for percentage rate Overhead.
If the Accounting Procedure had Operations and Maintenance Overhead of $250 per Producing Well per month, the Operator would not be allowed to charge any Overhead three months after the suspended well last produced.
If the Accounting Procedure had Operations and Maintenance Overhead of $150 per Producing Well per month and 10% of Operations and Maintenance Costs, the Operator would no longer be allowed to charge the $150 three months after the suspended well last produced, but the Operator would be allowed to charge the 10% percentage rate for any ongoing O & M expenses related to the suspended well.Hide response
Overhead (percentage) – allowable costs for trucking oil to cleaning facility
Can trucking costs of oil from a well to a cleaning facility be included in percentage based overhead calculation under the 1996 Accounting Procedure?
The 1996 Accounting Procedure (“PASC96”) defines “Operations and Maintenance” as activities and Material required to directly operate, repair and maintain wells and facilities on the Joint Property. Therefore trucking of clean oil or emulsion to a facility would fall under this definition.
Article II of the PASC96 outlines the type of charges that an Operator can charge to the Joint Account. Trucking of either clean oil or emulsion to a facility would be an allowable charge under Clause 207 “Services”.
Clause 301(a) of Article III of the PASC96 defines “Cost” as total expenditures pursuant to Article II of this Accounting Procedure, excluding those expenses pursuant to Subclause 209(b) and Clause 218 of this Accounting Procedure, and salvage credits for Materials retired, the value of injected substances purchased for enhanced recovery, custom processing revenues and charges and any additional exclusions as approved by the Owners.
Clause 302(e)(1), if it has been elected to be used, allows percentage based Overhead to be charged on “Cost” as defined in Clause 301(a).
As trucking of clean oil or emulsion is an allowable charge under Article II, and it fits the definition of Cost under Article III, the Operator is allowed to charge the percentage based Overhead stipulated in the PASC96.
It should be noted that the Operator cannot charge the percentage based Overhead on any fees paid to process the emulsion as “custom processing revenues and charges” are specifically excluded from the definition of Cost.Hide response
Overhead – allowable charges for shut-in wells
Can an Operator charge overhead on costs if the well has been shut in for more than 3 months. It is a PASC96 agreement.
The query references the use of PASC96. There are two Sub Clauses that determine if overhead is chargeable on operating costs after the well has been shut-in
If clause 302(e) (1) has a % (i.e.: 10%) indicated “and” includes a $ amount (i.e. $150) for Clause 302(e) (2), your clause would read as an example:
- For Operations and Maintenance
- 10% of Cost, and
- (2)$150 per Producing Well per month
In this example, the $150 per well per month would stop after 3 consecutive months of being shut in but the 10% charge would continue as an eligible charge to the well based on eligible “Cost” as outlined in 301(a). If there were no eligible costs, then the amount would be $0.
Clause 301(a) of Article III of the 1996 PASC Accounting Procedure defines “cost” as total expenditures pursuant to Article II of this Accounting Procedure, excluding those expenses pursuant to Subclause 209(b) and Clause 218 of this Accounting Procedure, and salvage credits for Materials retired, the value of injected substances purchased for enhanced recovery, custom processing revenues and charges and any additional exclusions as approved by the Owners.Hide response
Overhead and Admin fees for contract operated wells
Our company is questioning whether production accounting/administration charges are legitimate charges to the joint account. If the Contract Operator charges the Operator for a $250 overhead charge as well as the contractor operator fee is the Operator allowed to charge the Joint Account for the $250 fee and also charge the Joint Account for the Operator's overhead?Show response
This is a two part question.
Q1: Can an Operator charge the Joint Account for the Operator’s production accounting services?
Salaries and wages of an Operator’s production accountant whether the production accountant is an employee or a contract employee would be considered administrative in nature. An Operator’s administrative staff is not an allowable charge under the Accounting Procedure, unless the Operator has obtained the approval of Parties to charge these services to the Joint Account. Administrative services are deemed to be recovered through Article III – Overhead of the Accounting Procedure.
Q2: Can an Operator charge Producing Well Overhead if the Contract Operator of the well charges for production accounting services?
In order to place a well on production, the Joint Operations may need to tie the well into a third party processing facility. In many instances the Joint Operations must let the operator of the facility operate the well and, as a result, the Operator will enter into a Contract Operating Agreement (“Agreement”) with the facility operator (“Contract Operator”). Under the Agreement, the Contract Operator typical charges for the physical operation of the well, production reporting for the well and the Agreement may allow the Contract Operator to charge a handling fee on any third party materials or services they requisition to operate the well.
The Contract Operator on its invoice to the Operator may label the charge for the physical operation of the well as “Contract Operator”, the charge for production reporting as “Production Administration” or “Production Accounting”. The Contract Operator sometimes labels the charge for the production reporting as “Overhead”. Handling fees are usually labeled as “Handling Fees” or “Overhead”.
Regardless of how the Contract Operator labels the fees allowed under the Agreement, all of these fees are chargeable to the Joint Account as a contract service under Article II of the Accounting Procedure. The Operator is still entitled to charge Producing Well Overhead to the Joint Account under Article III. Producing Well Overhead is intended to compensate the Operator for its administrative services that are not chargeable to the Joint Account. The Contract Operator’s Production Administration fee should not be confused with, or thought to be in place of the Operator’s Producing Well Overhead charge.
Therefore, Non-Operators should not be disputing fees that are part of a Contract Operating Agreement, nor should they dispute the Operator’s right to charge Producing Well Overhead under the Accounting Procedure so long as the well is producing.
In general, once a well has been shut-in for greater than three (3) consecutive months, the Operator is required to curtail charging Producing Well Overhead. Please consult the specific Accounting Procedure related to the Joint Operation for the treatment of overhead for shut-in wells. In addition, the majority of Contract Operating Agreements provide for a reduction or elimination of the fees for the physical operation of the well and production reporting when the well is considered permanently shut-in or when the well has been formally suspended. Operators need to ensure they are not being overcharged by the Contract Operator in these instances.Hide response
Overhead (Operator's) – for contract operated wells/facilities
If an Operator under a Land Agreement contracts a 3rd party to physically field operate a well under the terms and conditions of a Contract Well/Facilities Operating Agreement and the $250/well/month Administration Fee (Schedule B of the Agreement) is charged to the Well Joint Account by the Operator, is it permissible for the Operator to also charge the Joint Account with the $150 to $250/well Operations and Maintenance Fee as per Clause 302 of the PASC Accounting Procedure attached to the Land Agreement?
The general Industry consensus is that either of the above fees are to re-reimbursed the party operating the well for the cost of accounting for the well production. If that is the case, why is this not detailed in the PASC Accounting Procedure Explanatory Text?Show response
Use of the term “administrative fee” or “administrative overhead” in Contract Well/Facility Operating Agreements has led to confusion regarding what the Operator of the Joint Operation is allowed to charge the joint account with respect to overhead.
The intent of Article III of the 2011 Accounting Procedure (“PASC 2011”) is to provide the Operator of the Joint Operation with a recovery for costs it incurs on behalf of the joint account that are not directly chargeable to the joint account under Article II of the PASC 2011. Those costs include, but are not limited to, land administration, indirect technical services, use of head office computer systems, various accounting functions such as approval and payment of invoices, production accounting, property tax reporting, etc. and other functions needed to ensure the Joint Operation is in compliance with various regulatory requirements.
Clause 207 of Article II of PASC 2011AP allows the Operator to charge the joint account for third party services incurred on behalf of the Joint Operation.
Most Contract Well/Facility Operating Agreements include a fee for the physical operation of the well owned by the Joint Operation, and where the well is tied into the Contract Operator’s facility, the Contract Operator may charge the Joint Operation with a separate fee (sometimes referred to as administration overhead or administration fee) to compensate the Contract
Operator for costs it incurs for any regulatory reporting it is required to perform on behalf of the Joint Operation. Administration fees charged by a Contract Operator could also include fees for serving as a Common Stream Operator (“CSO”).
The administration fee or administration overhead charged by the Contract Operator is part of the total fee to operate the well on behalf of the Joint Operation and is chargeable under Clause 207 of the PASC 2011AP. The administration fee charged by the Contract Operator should not be confused with the overhead that the Operator is allowed to charge under Article III of the PASC 2011AP. The Operator is still responsible for carrying out all work on the well (e.g. well servicing, repairs and maintenance) and the Operator is entitled to be compensated for the indirect costs it incurs to carry out that work.
PASC 2011 addresses this issue, however, older accounting procedures, such as the 1996 Accounting Procedure and Explanatory Guide, were silent on this issue as these types of separate charges were not as prevalent when those accounting procedures were drafted. However, just because a charge is not specifically dealt with in an explanatory guide to the older accounting procedures, does not preclude it from being a legitimate charge to the joint account. Explanatory guides are provided to supplement the reader’s understanding of the accounting procedure, but interpretation of a clause within an accounting procedure may extend beyond information provided in the explanatory guide.
Older accounting procedures may limit the cost of services that are directly chargeable to the joint account under Clause 207 or its equivalent clause in older accounting procedures. In instances where the accounting procedure would disallow the Contract Operator administration fee, the Operator could request partner approval to charge the fee to the joint account.
It is the opinion of the Joint Interest Research Committee that Contract Operator administration fees are chargeable to the joint account, unless the accounting procedure specifically indicates that administrative fees from a Contract Well/Facility Operating Agreement are not allowed.Hide response
Overhead rate – what rate applies to well suspension activities
How should we charge Well Suspensions for overhead purposes?
PASC 2011 Clause 301(E)(7) -- Specifically identifies Well Suspensions as a “Drilling” activity for overhead purposes.
PASC 1996 -- Well Suspensions are excluded from chargeable Operating & Maintenance activities. This would be a new project that occurs once production from the well or zone has ceased and as such it would no longer be classified as an “O&M” activity. It falls into the “Drilling” definition category that refers to “capping, abandoning and reclaiming” as a Drilling activity for overhead purposes. It should therefore be set up as a separate new project and not a continuation of the original drilling activity and as such, it would qualify for the “3/2/1” percent reset for development wells and not as a 1% extension of the drill program.
Overhead Rate Adjustment per wage index for prior years
The Operator had never applied the wage index factors on the Overhead Producing Well per month rate, and now has sent us an invoice for the correction going back the full 7 years of the contract. They have recalculated each month based on the new rate per Producing Well. This is a lot of money. Would your answer be different had they had only gone back 4 years.
Clauses in the PASC Accounting Procedures (1969, 1988 and 1996) that allow an escalation factor to be applied to the fixed rate Producing Well Overhead provide that Operator will or shall increase the fixed overhead rate by the escalation factor on July 1st of each year. Each specific agreement may differ so it is imperative that the parties follow the agreed-to terms, however most of the relevant PASC Accounting Procedures contain the following wording: "The adjustment will be computed by multiplying the rate currently in use by the percentage increase or decrease in the average ....... The adjusted rates shall be the rate currently in use, plus or minus the computed adjustment rounded to the nearest dollar." As an example, for an agreement effective in 2014, the first date the Operator would be able to do so would be July 1, 2015. If this was not done for July 1, 2015, then unless there are provisions in the governing agreement to the contrary, the next opportunity for the Operator to adjust the rate is July 1, 2016.
Whether an Operator can make adjustments in 2016 for 2015 or for periods prior to the effective date of the agreement depends on the provisions in the governing agreement. Under the 1996 PASC Accounting Procedure, the parties would need to consider whether the provisions of Subclause 107(c) permit the Operator to correct the overhead rate used in 2015, adjust the Joint Account for the difference and use the revised Overhead rate as the basis to apply the 2016 escalation factor. As to corrections for periods prior to 2014, given the number of variables to be considered, it may be beneficial to obtain the advice of Legal Counsel.Hide response
Overhead Rate Adjustment per wage index – 2015 looks high
Recently we received a copy of the PASC Overhead Rate Adjustment per the various sub clauses in the 1969, ’88 and ’96 PASC Accounting Procedures. I understand that the percentage rate increases and decreases are calculated using data from Statistics Canada. In general, the increases and decreases seem reasonable, save for the change from July 2014 to July 2015 where the rate increase is reflected at 16.03%. Given the economic times in the industry this increase appears quite out of line and as a result can have a significant impact on calculating an overhead increase. This overhead increase, in turn, becomes difficult to justify to partners.
Perhaps with some additional data or information we might feel more comfortable utilizing and/or accepting this rate. Is it possible that this rate was calculated because severances were included in the numbers provided to Stats Can? Please let me know your thoughts, or, as mentioned feel free to pass along to somebody that is better able to assist.
Overhead – Allowable Charge - Monthly Compressor Fee
Can the monthly rental fee for a compressor be included in a facility OH calculation (10%)?Show response
As long as your rental fee is a part of normal Operating and Maintenance and not part of a Capital project or has not been specifically excluded from the Overhead Cost/Rate Base in your Accounting Procedure; for any of the 1988, 1996 or 2011 PASC Accounting Procedures, the rental fee is allowed in the overhead calculation along with other Operating Costs.Hide response
Overhead re: Abandonment of a Drilling Well
The 1996 PASC Accounting Procedure has abandonment and reclamation work within the definition of Drilling. Drilling is 3/2/1 so it is safe to say that abandonment and reclamation would also fall into the 3/2/1 category for charging overhead?Show response
Your statement is correct; the definition of “Drilling” in the 1996 Accounting Procedure includes abandonment and reclamation, therefore an AFE to abandon and reclaim a well would attract the overhead rate prescribed under Clause 302(b) of the 1996 Accounting Procedure. While the 3/2/1 rate is fairly standard for the 1996 Accounting Procedure, the Operator should review the Accounting Procedure to confirm the rate for that specific Joint Account.
It should be noted that the above also applies to the 1969, 1976, 1983 and 1988 Accounting Procedures as abandonment and reclamation are included in the definition of “Drilling”. There is no definition for “Drilling” in the 1962 Accounting Procedure, but the overhead provisions of the Accounting Procedure stipulate that abandonment and reclamation attract the same overhead rate as Drilling.
The 2011 Accounting Procedure deals with abandonment and reclamation in a slightly different manner from previous versions of the Accounting Procedure. The Drilling overhead rate applies if a well is abandoned within 12 months after the rig release date or the well has never produced commercially, otherwise, the definition in 301(A) – “Abandonment and Reclamation” applies to the abandonment and reclamation of the well and again the Operator would apply the overhead rate stipulated in the Accounting Procedure.
The 1953 Accounting Procedure is the only Accounting Procedure that diverges from using the Drilling overhead rate for abandonment and reclamation. Abandonment and reclamation under the 1953 Accounting Procedure attract the Producing Well overhead rate.
Overhead – Mineral Lease Rentals
In what year were mineral lease rentals included as part of allowable costs for overhead calculation?
Mineral lease rentals have never been part of the allowable costs for the overhead calculation in any PASC Accounting Procedure.
On the other hand Surface Lease Rentals are an allowable cost for the overhead calculation.
Overhead on Lease Cleanup Costs
Under a 1981 CAPL Joint Operating Agreement and a 1983 PASC Accounting Agreement; the following situation:
A well was originally drilled two years ago under a Drilling AFE with the overhead 3-2-1 and due to the rush at the time to get wells drilled; the lease was never cleaned up from the drilling activity. The well has produced since it was tied in and continues to produce today.
Now we wish to prepare a new, information AFE for a lease clean up or Surface Compliance AFE, to comply with the Public Lands Act C&R for SD2010-02 and plan to send a copy to the other owners.
Will the cleanup AFE be considered as a separate project or will it be considered as an addition under a single program? Is this lease cleanup under the AER act and considered reclamation? What would be the overhead charged on the cleanup AFE be?
Please advise which PASC clause will apply to this situation. Would it be 101(e) Drilling or 101(c) Construction.Show response
The drilling process includes cleaning up the lease and therefore the cost of the cleanup is included in the AFE in one form or another. In your example, the lease cleanup should be treated as a continuation of the original Drilling program as it should have been done at the time the well was drilled. Therefore under your 1983 and similarly under the 1976, 1988 and 1996 PASC Accounting Procedures, this activity falls under the definition of Drilling and the Overhead Rate falls under the Drilling section of Clause 302. You should examine the level of expenditures against the original AFE to determine the appropriate Overhead Rate (3-2-1).
Regarding the 2011 Accounting Procedure, the activity still falls under the definition of Drilling in the Overhead section and the rate would be determined by the selection made in your signed agreement; Alternative A would be 2% and Alternative B in Clause 303(D) would be 5-3-1%.Hide response
IFRS – do PASC Accounting Procedures follow this standard
Is the PASC Accounting Procedure in accordance with International Financial Reporting Standards (“IFRS”)? In particular, is overhead, calculated under Article III of the Accounting Procedure, in accordance with IFRS?Show response
Q1 - Is the PASC Accounting Procedure in accordance with IFRS?
In general, IFRS 11 would govern situations where the PASC Accounting Procedure is used. The Accounting Procedure is typically attached to a CAPL Operating Procedure which, in turn, is attached to a head agreement. The agreement and the attached procedures would be defined as a “Joint Operation” under IFRS 11. A Joint Operation is a joint arrangement that is typically not structured through a separate vehicle (e.g. a separate company). In such cases, the contractual arrangement establishes the parties’ rights to the assets, obligations for the liabilities, rights to the corresponding revenues and obligations to the corresponding expenses. Parties would recognize only their working interest share, or proportionate consolidation, of the Joint Operation in their financial statements.
The PASC Accounting Procedure is strictly the mechanism for identifying the capital expenditures, revenues and operating expenses that can be charged or credited to the Joint Operation. It is then up to each party to account for its share of those capital expenditures, revenues and operating expenses in accordance with IFRS.
Parties would take a similar approach to accounting for their share of capital expenditures, revenues and operating expenses if they were preparing their financial statements under Accounting Standards for Private Enterprises (“ASPE”) or US Generally Accepted Accounting Principles (“US GAAP”).
Q2 - Is overhead, calculated under Article III of the Accounting Procedure, in accordance with IFRS?
Article III of the Accounting Procedure provides the Operator of the joint property with a mechanism for recovering costs indirectly related to the joint property. It is understood that the Operator incurs certain administrative expenses on behalf of the joint property that the Operator is not allowed to directly charge to the joint property under Article II of the Accounting Procedure. The overhead calculated under Article III compensates the Operator for these indirect expenses. Again, it will be up to each of the parties to account for the overhead expense in accordance with the IFRS.
In general, the non-operating parties, can treat any overhead they pay to the Operator as a direct cost with overhead attributed to operating expense recognized in earnings and overhead attributed to capital expenditures recognized as investing activities.
Technically, the Operator should reverse out its working interest share of the calculated overhead it charges to the Joint Operation, otherwise it results in the Operator effectively recording recoveries from itself. In practice, the Operator does not have to adjust its working interest share of the operating component of the overhead as both the overhead recovery and offsetting charge to operations are captured in earnings. The Operator’s working interest share of the capital component of overhead may not have to be reversed if the Operator is able to show that the overhead is in lieu of charging out administrative services that are directly related to those capital activities.Hide response
Orphan Wells – How to fund a bankrupt company
We are in the process of abandoning a well where one of our partners has declared bankruptcy. How do we, as the Operator, fund the bankrupt partner’s share of the abandonment?Show response
The Operator should consult the provisions of the Operating Procedure or similar agreement governing the Joint Account to determine what remedies are available to the Operator in the event a Non-Operator is in default.
Typically, Article V – Costs and Expenses of the CAPL Operating Procedure addresses the remedies available to the Operator where a Non-Operator has not paid its working interest share of expenses. If a Non-Operator is bankrupt, the Operator can give notice to the remaining Non-Operators requiring them to pick up a share of the defaulting Non-Operator’s interest. The fraction each of the non-defaulting Non-Operators would pick up is:
The working interest of the defaulting Non-Operator multiplied by the working interest of the Non-Operator divided by the aggregate working interest of all parties, except the defaulting partner.
This clause is to ensure that the Operator does not suffer a loss relative to the Non-Operators as a result of being the Operator.
The Operator also has the ability to apply for a Working Interest Claim (“WIC”) through the Orphan Well Association (“OWA”) and the Alberta Energy Regulator (“AER”) for the defaulting Non-Operator’s share of the well abandonment.
The OWA is an independent non-profit organization that operates under the delegated authority of the AER. The OWA is funded by the oil and gas industry through an annual Orphan Fund levy. The AER is solely responsible for deeming companies as defaulting working interest participants.
The Operator should consult both the AER and OWA websites for the process of making a WIC for a defaulting Non-Operator.
Assuming the AER and OWA accept and reimburse the Operator’s WIC for the defaulting Non-Operator, the Operator would then need to reimburse the remaining Non-Operators if the remaining Non-Operators were billed for a proportionate share of the defaulting Non-Operator’s working interest share of the abandonment.
In the event the defaulting party is the Operator, the AER will look to the remaining working interest participants (“WIP”) to fulfill the all abandonment obligations associated with the Joint Account. The WIP who abandons the well would then follow the process that has been outlined above.
General Information on the Orphan Well Association:
Abandonments and reclamations have become an important issue in the oil and gas sector, especially as it relates to orphan wells. Below is some general information concerning the OWA which was obtained from the OWA March 31, 2016 annual report (the report is available through the OWA website):
The OWA, established in 2001, is an independent non-profit organization that operates under the delegated authority of the AER. The mandate of the OWA is to manage the abandonment of upstream oil and gas orphan wells, pipelines and facilities and the reclamation of associated sites.
The AER is responsible for identifying and investigating potential orphans. Orphans are defined as specific properties that can be wells, pipelines, facilities or associated sites that have been investigated by the AER for legally responsible and/or financially viable parties. If no parties are identified, the AER then designates individual properties as orphans through a memo.
Funding of the OWA comes primarily from industry. For the 2015/16 year annually funding was increased from $15 million to $30 million. This is collected in two instalments from Industry (August and March). Funds are also provided to the OWA if the AER was holding an abandonment deposit under the LMR for a defunct company.
Although the OWA was established in 2001, funds have been going into an Orphan well fund since 1992. Since 1992 $27 million has been collected, of which $242 million was contributed by Industry and $30 million from Alberta Energy.
Since 1992, $247MM has been spend abandoning and reclaiming wells and facilities. Of that total, $82 million was spent on well abandonments, $138MM was spent on site reclamation, $9 million on pipeline and facility abandonments and $18 million on enforcement activities and WIP claims. In addition, $9MM was spent on the OWA administration.
For the year ended March 31, 2016, the OWA abandoned 187 wells (two of these were abandoned by the AER), 164 pipeline segments and four licensed facilities, removed surface equipment from 71 well sites and received reclamation certificates for 10 sites. Since inception, the OWA and AER have abandoned 889 wells and received reclamation certificates for 536 sites.
As at March 31, 2016, the OWA had an orphan inventory of 768 wells, 856 pipeline segments and 540 surface reclamations.As at December 19, 2016, the OWA had an orphan inventory of 1,395 wells, 1,617 pipeline segments and 688 surface reclamations.
A company, who abandons a well/facility/pipeline, can submit a working interest claim (“WIC”) to the OWA through the AER to collect a defunct partner’s share of the abandonment. (“A WIP is any party to a joint operating or other agreement under which the party is entitled to a proportionate share of cash flows as well as the responsibility for the same proportionate share of costs”). The OWA paid out $2.7 million in WIC for the year ended March 31, 2016.
A WIC is initiated by sending the OWA an AFE for approval. WICs are then submitted to the AER with a letter and other supporting documentation. The AER Liability Management Group will confirm if the WIC is eligible and if eligible, turns the WIC back over to the OWA. Costs are then submitted to the OWA for review and reimbursement to the Operator.Hide response
Payout accounts – marketing fees for drill and complete projects
Seeking feedback with respect to companies charging marketing fees to a payout account for drill and completion AFEs. My take on it would be that marketing fees would not be chargeable as 100% of the revenue and volumes belong to operator (assuming there are no other partners) until payout has been achieved and therefore the operator should not be charging itself marketing fees. Please advise.Show response
Most clauses in the agreements that grant the operator the authority to charge marketing fees are a punitive measure (and cost recovery mechanism) arising from a party (who owns production) failing to make appropriate marketing arrangements, failing to make appropriate storage arrangements and/or failing to take its production in kind. In these situations, if the operator has to make any marketing arrangements, then it can charge a marketing fee.
In a payout scenario, the non-participating party owns no production so it has neither failed to take in kind nor failed to make marketing arrangements and therefore no marketing fee would apply.
This is presuming of course that there's no mention of marketing fees as being an allowable charge to the payout account in either the definition of payout nor the related payout provisions in the agreement.
Payout – should Gas Cost Allowance be included
Can GCA (Gas Cost Allowance) be included in the payout account?Show response
GCA (Gas Cost Allowance) is an abatement calculated at the facility level based on the cost of the facility and the percentage of crown gas being processed at that facility. GCA is not a well specific credit and under Clause 1007 of the CAPL Operating Procedure, abatements received pursuant to the Regulations are to be excluded from the payout calculation. Therefore GCA should be excluded from any payout calculation.Hide response
USA – accounting procedure for the oil & gas Industry
What model describes the accounting standard setting in the United States? Is the accounting standards setting in the United States public/private approach? Are the standards set by private sectors and enforced through governmental agencies?Show response
COPAS (Council of Petroleum Accountants Societies) is the association that sets the Accounting Procedure Standards in the U.S. The link to the COPAS website (www.copas.org) is on the PASC Related Sites page. The COPAS Model Form Accounting Procedures and Interpretations can be ordered directly from COPAS.
The COPAS Accounting Procedures are created through a consultative process involving representatives of various E&P companies and then approved for use by representatives of all US Petroleum Accounting Societies.
As to the involvement of governmental agencies, you may wish to contact COPAS for response.
Joint Interest Audits - Statute of Limitations
If an audit has been conducted and Operator is responding to each Exception within 6 months of receipt and cooperating as per the PASC Joint Interest Audit Protocol (AG – 5), is there justified reasoning for a Non-Operator to request/insist a Standstill Agreement be put into place?
Was my understanding if we waived, allowing the Non-Operator to audit ‘2013’ and audit was performed in 2017, there is no longer an issue with the Statute of Limitations other than what is outlined in the PASC accounting guidelines (AG -5)? Can you assist with my interpretations and/or provide some clarification?Show response
The Operator allowed a Non-Operator to perform an audit on 2013 charges in 2017. Their right to audit 2013 charges expired on Dec 31, 2015.
The Limitations Act of Alberta as amended by the Industry Agreement states that the Non-Operator must file a claim (in a court of law) within 2 years following the time the agreement allowed the audit to be performed for claims disclosed by an audit. (For all other claims, 4 years from when they knew or ought to have known.)
Therefore in order to protect their right to file a claim as that right will expire on January 1, 2018 for any claims disclosed by an audit, the Non-Operator has two years after Dec 31, 2015 to file a claim so must either:
- have a standstill agreement in place before Dec 31, 2017, or
- file a statement of claim before December 31, 2017 as that would stop the clock.
In either case it is protection for the Non-Operator under the Limitations Act as amended.
You can read more about the Limitations Act and how it works with oil and gas agreements in the PASC publication; GP-15, 2017 Alberta Limitations Act.Hide response
Audit Team was refused access to Operator’s records despite proper notification.
Can an Operator refuse to allow an audit team into the Operator’s work area despite proper audit notification and prior acceptance of the audit time reservation.Show response
Neither the provisions of the PASC Accounting Procedure nor any audit-related guidance issued by PASC, such as the suite of PASC JV Audit Guidelines, apply to the situation described.
However, provisions dealing with the revoking of rights, such as audit rights, access to information, etc. under an agreement are typically found in the governing agreement. Using the more popular versions of the CAPL and PJVA industry models to illustrate, provisions that allow the Operator to take certain actions or exercise certain remedies in the event of non-payment by a partner are outlined in the Operator’s Lien provisions, i.e. clause 505 of the 1990 CAPL Operating Procedure (if the matter pertains to operations under a JOA) and clause 602 of Exhibit “A” (Operating Procedure) to the 1999 PJVA Model Facility CO&O Agreement (if the matter relates to facility operations).
Both Paragraph 505(b)(ii) (1990 CAPL) and Paragraph 602(b)(ii) (1999 PJVA) have similar language and neither requires prior notice be issued by the Operator for the remedies to be exercised:
If a Joint Operator (Owner) fails to pay or advance any of the costs or expenses incurred for the Joint Account which are to be paid or advanced by it within the time period prescribed by the Accounting Procedure……. Operator may, without limiting Operator's other rights in this Operating Procedure (as contained in this Agreement) or otherwise held at law or in equity……. withhold from such Joint Operator (Owner) any further information and privileges with respect to operations hereunder (Joint Operations)…… which information and privileges shall be conveyed or restored, as the case may be, to such Joint Operator (Owner) upon such default being fully rectified.
While the Accounting Procedure and/or governing agreement may grant the right to audit, subsequent actions of the parties, events, and provisions under the Agreement may limit that right.Hide response
Charging Rig Move Costs
What are the guidelines for charging Rig Move costs for these scenarios?
- Mobilization (including rigging up and move in to the first well, inspection)
- Demobilization (including rigging down, racking, move out to contractor’s yard, inspection)
- Moving from well to well in the same program.
Moving from one program to another program or operator (including rigging down and move to an all-weather road).Show response
Mobilization means, the cost of moving a rig from the contractor’s yard or their rack site in the field or from another location to an all-weather road closest to the first well including inspection costs.
Demobilization means, the cost of moving a rig from an all-weather road closest to the last well drilled to the contractor’s yard or their rack site in the field including inspection cost.
Note that Mobilization and Demobilization should not include “Rigging Up” and “Rigging Down”.
Operators drill wells under one of two types of programs, and the rig move costs should be charged for each as follows, subject to the additional notes below:
- Single well program – Whether the rig comes from the drilling contractor’s yard, a rack site in the field, from a well drilled by another Operator, or from another location, not controlled by the Operator, the mobilization costs should be charged to the well. After the well is drilled, the demobilization costs should also be charged to the well if the rig is returned to the drilling contractor’s yard or to a rack site in the field. However, if the rig is moved to a well that is being drilled by a different Operator, the well should pay for rigging down and move to an all-weather road.
- Multi-well program –The total Mobilization and Demobilization costs, including the cost of moving the rig to the nearest all-weather road and the rig moves from well to well or to a pad within the program should be pooled and then allocated equally to each well drilled in the program.
Rigging up and rigging down activities are excluded from Mobilization and Demobilization and should be charged directly to each individual well. That being said, if the costs for each well are approximately the same and there is common ownership of all wells in the program, then these costs could be included along with Mobilization and Demobilization and allocated equally to each well in the drilling program, including a pad.
Costs of rig moves to a location other than the drilling contractor’s yard or to a rack site in the field should be borne by the next receiving location and subsequent Operator, except the rigging down and move to the nearest all-weather road should be the cost of the last well. In general the departing location should be responsible for the rigging down costs and of moving the rig from the wellsite to the nearest all-weather road, which in most cases may be just outside the fence of the departing well. However, there can be cases where the departing location is in rugged terrain and if there has been heavy rain or snow, extra costs may be incurred for equipment to help tow trucks carrying the rig to the all-weather road.
The above response assumes routine Western Canada operations. If the operation relates to Frontier, Artic or some other special operating condition, the parties best review the CAPL Operating Procedure for guidance on how these costs are to be shared. In the Addendum to the Annotations for the 2015 CAPL Operating Procedure, the suggestion was made that the parties should consider modifying the Operating Procedure to “manage cost allocation issues associated with the north, particular for the far north:
- Allocation of mobilization costs to the north across a drilling program
- Allocation of standby charges inherent in maintaining equipment in areas of the north on a year round basis
- Allocation of charges for use of a staging and base camp area owned by fewer than all of the parties.”
The above factors may also be relevant to remote locations.Hide response
Where do I find documentation on Payout Operating Costs.
Specifically the explanation for charging Fees for use of facilities when well is not charged them.Show response
PASC has a publication on Payout Accounting (AG-01) and you can see a copy on the website.
We suggest you review the wording in the CAPL Operating Procedure attached to your agreement to ensure you are in compliance. If there is no reference to Facility Fees in your Operating Procedure, the wording of the 2015 CAPL Operating Procedure could be followed.
The following is a summary of the wording in that 2015 CAPL Operating Procedure.
Facility Fees need to be included in the payout calculated for each party and are those actual costs per an arm’s length third party contract to process the product from the new well through a third party facility. If facility capacity is owned by one of the parties, the fee to be used in the payout calculation and statement should be:
- the fee specified under a separate agreement negotiated between the parties; or
- the fee normally charged to a third party for a comparable use under an arm’s length transaction.
For all other circumstances a fee in which the capital component is determined using Jumping Pound-05 methodology and the operating cost component is calculated and assessed on the basis of the facility throughput costs.Hide response
The above opinions are based upon limited knowledge of the specific circumstances. In the event of a dispute, you may wish to engage appropriate legal guidance.