Natural Gas Liquids and ISC Questions and Answers


The following questions were asked by Industry at Town Hall training sessions on Natural Gas Liquids (NGLs) and In-Stream Components (ISCs), held by the Department of Energy, for the stakeholders. Approximately 250 individuals attended the presentations held in Calgary from June to September 2002. These sessions were used to encourage questions and have advisors explain how the NGL changes would impact royalty reporting.

These questions from industry are provided for your information:

  • the questions are related mostly to the changes in volumetric reporting

  • to the revisions in the calculation of the Crown Royalty share resulting from the recognition of ISCs within the gas stream

  • to the revised prices and royalty rates

  • to the modifications in data retrieval in Registry and their impact on royalty reporting by industry clients

​Raw Gas Allocation (RGA) Information submissions

When does a client submit an RGA? Is the seller exempt from submitting an RGA if he or she is selling raw gas and not residue gas?

A client submits an RGA for all raw and residue gas sales that occur within the royalty network. The need to submit an RGA depends then on the network situation. If gas is sold after a gas plant but before a straddle plant (specifically mainline), then an RGA is NOT required. If the gas is sold after a gas plant, but still within the royalty network (i.e. does not flow to a deep cut), then an RGA IS NOT required.

When a company sells raw gas at the wellhead, and does not operate a disposition facility, does it still need to file an RGA? 

Yes, the company must submit an RGA as the raw gas sale at a wellhead is within the royalty network. Whether the company is an operator or a non-operator is immaterial.

If the same company sells gas downstream of a shallow cut plant, and the gas goes to a deep cut plant, this gas is considered processed gas. Is an RGA required? If this company does not operate any facilities, does it file volumetric ISC submissions?

No, the company does not need to submit an RGA as the gas is being sold downstream from a shallow cut plant, and this sale occurs out of the royalty network. Not all facility operators are required to file ISC volumetric submissions. Please refer to the ISC Reporting Table included in the June 2002 Supplement of the Gas Royalty Information Bulletin for a list of required reporting.

If a company processes its gas at both the shallow cut plant and the deep cut plant and sells its gas at the Alberta border, is an RGA required and does the ISC have to be reported?

No, the company does not need to submit an RGA as this sale occurred at the border and is considered to be out of the royalty network. However, since there are volumes that trigger royalty at the Gas Plant (shallow cut), we require a Disposition (DISP) from the shallow cut plant operator. Consequently, the Field Straddle (deep cut) operator is required to submit ISC volumetric submissions in the Petroleum Registry. Please refer to the ISC Reporting Table for submission requirements. 

Why are sellers of raw gas, rather than purchasers, required to submit an RGA in the Registry?

The sellers (producers) pay royalty to the Department of Energy and generally know the composition of the gas. This is especially true, if several raw gas streams are commingled in the field.

Do downstream operators and purchasers have a liability if upstream sellers don't submit an RGA?

No, there is no liability to the downstream operators and purchasers as they are not responsible for submitting an RGA. In the absence of an RGA, Crown royalty valuation will not be treated as a Raw Gas Sale.

How often are RGAs submitted? (Static vs. Dynamic)

An RGA does not need to be filed every month if there is no change: i.e. if it's still an in-network sale for the same stream, the same sales location, the same delivery facility and with the same RGA and ISC factors.

RGA information is effective dated and the Registry will pass on the active RGA each billing period to the Gas Royalty Mineral Revenue Information System (MRIS), if an updated one is not required.

What supporting details does Audit require to support the ISC factors on the RGA?

 

 

              

​In-Stream Components (ISC) Information submissions

How often are clients expected to submit ISC volumetrics?

Clients are expected to report their ISC volumetrics monthly, as they do their other volumetric submissions. 

Carbon Dioxide (CO2-1C) and the forward products such as inerts are not required for ISC balancing/reporting. However, some of their products (components) have heat value. Why are they not reported?

All components, if they exist in the composition analysis should be reported. Inserts are excluded from the facility average calculations and the ISC balancing, as a safeguard to ensure that the facility average price and rate are not skewed. 

If gas were sent from a NOVA pipeline to an injection facility (IF), would ISC filing be necessary, and if so, who would be responsible for this submission? What would happen if there were no other receipts at the IF?

Yes, ISC filing would be required and the IF operator would be responsible for submitting the receipts. In absence of other receipts, the receipts from the pipeline operator would be used to determine the Facility Average Royalty Rate (FARR%) and the Facility Average Price (FAP) calculations at the IF. 

Who is responsible for filing the ISCs, when gas is delivered to a fractionation facility?

In most cases, gas delivered to a fractionation plant is for the purpose of further extraction of Specification (SPEC) products. Since there is no gas being processed, ISC reporting is not required at this facility.

Is ISC balancing done only at Meter Stations?

Yes, receipts at meter stations (excluding inerts), are compared to dispositions at meter stations for each ISC receipt. 

Can Gas volume and energy be submitted separately from the corresponding ISC volume and energy?

No, the edits in the ISC Volumetric Submission will reject a submission if the aggregate ISC volume and energy and corresponding Gas volume and energy are not submitted together. 

How is the ISC heat calculated? How were the heat value ranges determined? Will a submission be rejected if the heat is not within the range on the table?

The following is a sample of how the ISC GJ are determined:

Sample In-Stream Component GJ Determination
Assuming residue gas production of 2,000,000 E3M3 in a production month

 

  Reported Residue Gas Volume (E3M3) -->  2,000,000   
In-Stream ComponentReported Mole %, Production MonthMonthly production
Volume by In-Stream Component, E3M3
GJ/E3M3
1998 SI Handbook
Reported GJs
for In-Stream component 
 C1  88.00% 1,760,000.0  37.708 66,366,080.0 
 C2    2.00%      40,000.0  66.065  2,642,600.0 
 C3    3.00%      60,000.0  93.936  5,636,160.0 
 iC4    0.50%      10,000.0121.406  1,214,060.0 
 nC4   1.00%      20,000.0121.794  2,435,880.0
 iC5   0.25%       5,000.0149.363     746,815.0
nC5   0.50%     10,000.0149.656  1,496,560.0
CO2   3.95%     79,000.0    0.000                0.0
Nitrogen   0.70%     14,000.0    0.000                0.0
Other   0.10%       2,000.0    0.000                0.0
TOTAL 100.00% 2,000,000.0 80,538,155.0

Note: May include Argon and Helium. These are trace gases not often detected by the gas analysers.

The Department's engineers have designed the following Heat Range Table

ISC Product Code  ISC Product Description  Heat Value Range 
 C1-IC Methane ISC  36.000 - 38.700 
 C2-IC Ethane ISC  63.000 - 69.000
 C3-IC Propane ISC  91.000 - 97.000
 C4-IC Butanes ISC118.500 - 124.700
 C5+-IC Pentanes Plus ISC145.700 - 290.000
 CO2-IC Carbon Dioxide ISC    0.000 - 0.000
 H2-IC Hydrogen ISC    9.000 - 15.000
 H2S-IC Hydrogen Sulphide ISC  20.800 - 26.800
 HE-IC Helium ISC    0.000 - 0.000
 N2-IC Nitrogen ISC    0.000 - 0.000
 O2-IC Oxygen ISC    0.000 - 0.000
 SUL-IC Sulphur ISC    0.000 - 0.000

Where ISC reporting is required, aggregate ISC volume and energy must equal corresponding Gas volume and energy (within a tolerance of 0.100 10³ m³ and 1.000 gj) or both ISC and Gas volumetric submissions will be rejected. ISC heat value (gj/103 m³) must be within the specified heat value range for each ISC product. The heat check will NOT be performed for volumes that are <2 and gj<65.

How is the ISC breakdown reported for non-reporting pipelines? What is the source of the ISC breakdown coming from a non-reporting facility such as the Pipeline Alliance? Would such situations be subject to audit?

 

 

 

​Client Impact

Are ISC imbalances shown immediately, upon entry in the Registry?

No, the ISC balancing process is not shown on the Registry. This process is generated by MRIS on day 35, following the month of production. 

When there are ISC imbalances, why don't we reject submissions, rather than apply defaults? Will the owners be notified of the defaults and if so, when?

Due to the impact of meter station receipts on the FARR% and FAP calculations, it is in the Crown's interest to use a default price to charge royalty rather than reject receipts that cause an imbalance. This will also benefit royalty clients, as the opportunity for these imbalances to be corrected rather than rejected outright, will result in fewer default prices being used. Royalty clients will be notified of the defaults in a Default Report and in the FARR%/FAP supporting details, included in their monthly invoice package, identifying where ISC default values have been used. 

How often does the CSO have to perform a composition analysis? Are there any stipulations and how often do they change?

A composition analysis can be prepared in accordance with an individual company's business practice, subject to Department audit.

Do pipeline receipts provide the necessary ISC component breakdown? Is there a compliance mechanism to ensure this is provided? How does the producing facility operator source the ISC composition for non-reporting pipelines?

Pipeline operators with receipts from gas meter stations (subtype 631 and 637) are required to state the ISC components when submitting their gas receipts in the Registry. The Registry would reject any gas receipts that were submitted without the ISC receipts and the pipeline operators would also be subject to possible Departmental provisional assessments and Alberta Energy and Utilities Board penalties. A facility operator delivering to a non-reporting meter station/pipeline is required to submit both the gas and ISC dispositions in the Registry and must obtain the ISC information from the non-reporting pipeline operator. If ISC information is not reported where required the Registry would reject the submission. (Please refer to the ISC Reporting Table). 

Do Stream Allocation Factor (SAF) and Owner Allocation Factor (OAF) submissions apply to production or sales volumes?

SAF/OAF submissions apply to sales volumes. 

Can a service provider upload ISC dispositions to the Registry?

Yes a service provider can upload ISC dispositions in the same way that is done for all other volumetric submissions.

All IF activity influences the valuation of the FAP and the net Gas Transportation Adjustment. Could producers' FARR% be affected by another party delivering to an IF? Could transportation allowances be diluted by others delivering to a larger sale?

The principles supporting FARR% and FAP were derived in consultation with Industry in response to the NGL royalty changes initiative. All reporting affects the facility average royalty rate and valuation price. 

What is an Included Pipeline?

Included pipelines refer to gas pipelines identified by the Department for which meter stations factors will be calculated. Pipelines are included if they have regulated tolls (not a proprietary pipeline) and physical access to the ex-Alberta market either directly or by interconnect.

At this time, Included Pipelines are:

  • Nova Gas Transmissions Ltd. (NGTL)

  • Northern Utilities Limited (operating as ATCO Pipelines)

  • ATCO Gas and Pipelines Ltd. (formerly Canadian Western Natural Gas Company Limited operating as ATCO Pipelines)

  • Westcoast Transmission Company (Alberta) Ltd.

  • AEC Suffield Gas Pipeline Inc.

  • Alliance Pipeline Limited Partnership (For Gas ISC reporting, Alliance is the only non-reporting pipeline.)

What is the meter station factor? When did we begin to use it?

This is used to calculate the transportation adjustment to the Gas Reference Price effective July 2001 and the Facility Average Prices effective October 2002. The transportation adjustment was implemented to reflect changes to NGTL's transportation rates, from a postage stamp rate to a receipt point specific rate. For a more complete description of the meter station factor calculation, refer to Appendix E in the September 1, 2001 Natural Gas Royalty Principles and Procedures document.  The meter station factor is a calculated factor, and does not have a tolerance. 

Why implement this policy when products are already extracted as much as they can be extracted? This is a concern for those who are delivering out of the province for extraction. Is the Crown is penalizing a large group for a small group's problem?

The policy is designed to level the playing field by eliminating the royalty consideration from the business decision. It applies the same royalty rate to each product, liquid or ISC. The introduction of price sensitivity in setting royalty rates for C3 and C4 will assist producers when low price levels occur, and better tailors royalty rates to available economic rent. 

 

​Rates and Prices

How are the reference prices calculated?

The Gas Reference Price is determined by the Minister for each production month, and is used to value raw gas and residue gas for royalty clients who choose the Gas Reference Price method for production periods between January 1994 and September 2002. For the calculation of the current Gas Reference Price refer to Appendix D of the Alberta Natural Gas Royalty Principles and Procedures, effective September 1, 2001.

The in-stream component reference prices are determined by the Minister for each production month effective October 2002, and are used in the calculations of the facility average prices used to value raw gas and residue gas for royalty clients who choose the Gas Reference Price method. The information reported in the existing Alberta Gas Reference Price model are used to calculate ISC Reference Prices (C1, C2, C3, C4 and C5+), along with pipeline ISC and mainline straddle plant production.

Why is the ISC price different from the extracted product?

Extracted product reference prices for C3, C4 and C5+ are determined from the market prices for those extracted products. The extracted product reference price for C2 is the equivalent of the C2 ISC Reference Price since there is no actively traded market in Alberta for C2.

ISC Reference Prices apply to the in-stream components contained in the gas stream at the point royalties are triggered. They are calculated using gas prices for ISC quantities consumed as gas and shrinkage gas prices for gas extracted at mainline straddle plants. This method is a more accurate value of the gas stream versus valuing the in-stream components of the gas stream at extracted product prices.

Will the ISC reference price be consistent with the extracted product reference price? If their prices are different, how will the ISC R% be the same as the extracted product R %?

The ISC reference price is different from the extracted product reference price. Refer to question 34. A single royalty rate calculation, based on the ISC reference price, applies to both the in-stream component and the extracted product (for C2, C3, C4). A single royalty rate calculation for C5+ uses the extracted product price and applies to both the in-stream component and the extracted product. 

Why is raw gas used as lease fuel valued at 100% of the Gas Reference Price, when subsequently processed raw gas is valued at 80% of the reference price?

Raw gas used as lease fuel is consumed without subsequent processing. The Crown does not share in processing costs and therefore does not need to discount the valuation price in lieu of cost allowances.

When is the Gas select price available?

The new Gas select price for a production year is published annually in the February Information bulletin. This price applies to the Gas Reference Prices calculated for all production months in that year. For more information please refer to the Natural Gas Royalty - January 1996 Production Month Information Letter 96-09.

How is the minimum of 15% established for Propane and Butane royalty rates?

The 15% royalty rate reflects the minimum base rate before low productivity adjustment that has been part of Alberta's royalty framework since 1992. The rate starts at a minimum of 15% and climbs to a maximum of 35% for "old" gas and 30% for "new" gas, depending on price. These rates previously applied to gas, with no distinction for propane or butane. When extracted as liquids the rate for both propane and butane was previously 30%. The NGL changes extend the gas royalty formula to liquid propane and butanes, thereby making the rates for propane and butanes sensitive to the level of prices. 

Why does the '40' in the Royalty formula remain constant for gas when the formulas for other products change as per maximum and minimum?

These were marginal rates set for the 1994 Royalty Simplification Regime, endorsed by Industry and the Department. 

                    

​Client Information

How will clients know the Heat Value Range?

This information is published in the December 2002 Gas Royalty Calculation Information Bulletin (Attachment 4).

Will the Department publish the ISC royalty rates and prices?

Yes, the Department has published ISC product pricing information in monthly Information Bulletins since the December 2002 Gas Royalty Calculation Information Bulletin.

Will the Department publish the FARR% and FAP information?

The FARR% and FAP information will not be published in the monthly Gas Royalty Bulletin. However, royalty clients will receive supporting details on the FARR%/FAP and RARR% calculations in their monthly invoice package. The FARR% and the Raw Gas Average Royalty Rates (RARR%) are not generated until invoice calculation is completed.

Will the Crown Invoice and Crown Royalty Detail (CRD) change and will the supporting reports be available on the Registry in the same way as the Invoice/CRD is?

The format of the Crown Invoice and CRD will not change. However, the CRD Calculation and the Crown Royalty Detail Volumetric reports have been revised to include the Volumetric, SAF and OAF details for post Registry implementation periods. For samples of the Crown Royalty Detail Reports refer to Attachments 12 and 13, in the October 2002 Gas Royalty Calculation Information Bulletin. Since the royalty rate and valuation price for Gas can be different at each royalty assessment facility, the FARR/RARR% and FAP calculations have been incorporated in supplemental reports which can be downloaded in UDF (EDI)/CSV/PDF/TXT formats. Royalty clients can retrieve these reports from the Registry, for each of the calculations, in their Monthly Invoice Package. For details on the supplemental reports, please refer to the July 2002 Gas Royalty Calculation Information Bulletin.

Will the ISC Balancing Discrepancy Notification be available in the Registry?

Yes, if a client (meter station operator) has an ISC balancing discrepancy, the ISC Balancing Discrepancy Notification will be available under "Ministry Reports" in the Registry.

Who is the contact for Registry formats?

Clients may contact the Registry Service Desk at (403) 297-6111.

Will the Department consider calculating facility average royalty rates and prices at a client/facility level?

The Department will consider this, however, a client's request to move NGL reporting to a client/ facility level should go through either the Industry Benefits Committee (IBC) or Business Design to the Registry Advisory Committee (RAC). The RAC is part of the ongoing governance of the Petroleum Registry of Alberta. 

How will inventories be dealt with in the Registry? Will the negative inventories be accepted or not?

Yes, the Registry carried forward inventories from September 2002 production (INVCL from September became INVOP for October). Inventory adjustments can be negative, however opening and closing inventories must always be positive. Negative inventories are not allowed with a volumetric submission.