This month’s Oil & Gas Measurement Podcast episode features Colby Ruff discussing the regulation differences between the United States and Canada for the oil and gas industry, as well as Canada’s program EPAP.
In this month’s episode, you will learn about custody transfer measurement, audits, and how the Canadian government keeps the senior executives responsible.
Measurement in the Great White North Show Notes, Links and Insider Terms
- Colby Ruff is an upstream oil and gas facility measurement specialist at his own consulting business, Measurement Optimization Corp.. Connect with Colby on LinkedIn.
- Measurement Optimization Corp. specializes in optimizing upstream oil & gas facility measurement and reporting while maintaining regulatory compliance in AB, SK, and BC.
- Upstream is the operation stage in the oil and gas industry that involves exploration and production.
- Midstream is the processing, storing, transporting and marketing of oil, natural gas, and natural gas liquids.
- Downstream is the process involved in converting oil and gas into the finished product, including refining crude oil into gasoline, natural gas liquids, diesel, and a variety of other energy sources. The closer an oil and gas company is to the process of providing consumers with petroleum products, the further downstream the company is said to be.
- Rule 17 (or Directive 017) in Canada defines the requirements for measurement points used for accounting and reporting purposes, as well as those measurement points required for upstream petroleum facilities and some downstream pipeline operations under existing regulations.
- EPAP (Enhanced Production Audit Program) is a program that helps companies improve their measurement and reporting processes, in order to meet AER requirements in Alberta and MER in Saskatchewan.
- Enterprise Resource Planning Systems (ERPs) are used in businesses to manage company resources, integrate tasks, manage risks, localize financial accounting, and ensure quality checks.
- Liquefied petroleum gasses (LPG) is a group of hydrocarbon gasses, primarily propane, normal butane, and isobutane, derived from crude oil refining or natural gas processing.
- NGL – Natural Gas Liquids are components of natural gas that are separated from the gas state in the form of liquids. This separation occurs in a field facility or a gas processing plant through absorption, condensation, or other methods.
- LACT stands for Lease Automatic Custody Transfer. A LACT Unit is a piece of oil and gas equipment used to sample and measure oil so it can be transferred from one company to another.
- Directive 076 – Operator Declaration Regarding Measurement and Reporting Requirements established specific requirements and controls that will help operators keep their reporting and measuring in line with what AER requires.
- Petrinex is an online system for volumetric reporting, used by B.C., Alberta and Saskatchewan. It is an internet-based, joint strategic organization supporting Canada’s upstream oil and gas industry and is represented by both Government and Industry.
- Sulfur oxides or SOx are compounds formed by the reaction of sulfur with oxygen when a sulfur-containing hydrocarbon is burned.
Measurement in the Great White North Full Episode Transcript
Weldon Wright: Welcome to episode 23 of the “Oil & Gas Measurement Podcast,” sponsored by GCI, Gas Certification Institute.
For more than 20 years, GCI has been providing measurement fundamentals training and measurement standard operating procedures to the oil and gas industry, and now proudly offer the Muddy Boots Online field operations platform. Let GCI show you how Muddy Boots can streamline your field measurement operations.
Announcer: Welcome to the Oil & Gas Measurement Podcast, where measurement professionals, bubba geeks and gurus share their knowledge, experience, and likely a tall tale or two on measurement topics for the oil and gas industry. Now, your host, Weldon Wright.
Weldon: Hello, and welcome to episode 23 of the “Oil & Gas Measurement Podcast.” I’m your host, Weldon Wright of FpvPrime Measurement Consulting. I’m here today with Colby Ruff of Measurement Optimization Corp.
We’re going to talk about how things are going up north of the border. Before we do that, Colby, thanks for being here. Tell us a little bit about yourself and how you got where you are in the gas industry.
Colby Ruff: Thank you, Weldon, for the invitation to attend the podcast today. Very happy to share some insights on how we do measurement up here in Canada. I am an upstream oil and gas facility measurement specialist. I have my consulting business, Measurement Optimization Corp.
I’ve been out consulting now for just about three years. Prior to that, I was the measurement specialist at the Alberta Energy Regulator, which is a provincial regulator that oversees oil and gas production here in Alberta.
Maybe I’ll just take a couple of minutes and give a little bit of a history of my experience in the oil and gas industry. I won’t dwell on it, but some of it might be relevant. As you can tell, maybe you can’t because you don’t have a picture, but I’ve been in the industry for quite some time.
I entered back in the early ’80s after graduating from the Southern Alberta Institute of Technology here in Calgary. It’s a polytechnic that has an upstream oil and gas program. In the ’80s, I worked for a few different oil companies here in Calgary, Mobile Oil, Canada, Canadian Hunter, West Coast Petroleum.
I was primarily doing reservoir engineering work and production engineering work. I did that for about eight years, and then changed career paths a little bit.
I left the operating companies and went and worked for a few different service providers that developed software programs for the upstream industry, economic evaluations, and various engineering packages. I worked for a data vendor as well. I did that for about 10 years.
My last experience in that regard was working for Schlumberger Information Solutions here in Calgary, where I was their business development manager for outsourced data management, and helped them build their LiveQuest business model, which was ASP server and back in those days was quite new.
It’s pretty normal these days, but it was new and shiny back then. After I worked for Schlumberger, I spent a couple of years working for the Southern Alberta Institute of Technology in their corporate training department.
Specifically, what I was doing is creating and delivering training programs for oil and gas companies, specifically on the upstream side. It was through that work that I was introduced to a fellow by the name of Dave Hill at the Energy and Utilities Board. That was around 2004.
I was putting together some training for his folks in the production operations group. He looked at me and said, “Hey, we’ve got a position we’re trying to fill. We think you’d be a good fit.” I agreed, and that’s how I got employed with the regulator here in Alberta.
That was 2004. My first role there at the regulator was in their flaring and venting team, specifically dealing with what was called Directive 060 – Upstream Flaring and Venting Guide. The whole idea there was working with upstream operators to help them minimize their solution gas flaring and venting from oil operations.
Over time, that mandate expanded to reducing flaring inventing from all sorts of facilities, gas plants, gathering systems, and so on. After doing that for a couple of years, I actually moved into the measurement space and was able to work with Directive 017, which is the measurement directive with the Alberta Regulator.
I spent two years doing that, and then I actually got into a leadership role. I became the section leader of production operations. That section had four teams. There was a measurement team, production audit team, gas plant performance, and flaring and venting team.
I was in that role for just over six years, when our then measurement specialist, Bill Chung, informed me that he’s going to be retiring soon. We had to look for someone to backfill for his role. At that time, I’d been in the industry for a number of years and I was starting to look ahead to retirement thinking that when I retire, perhaps I want to retire completely. I might like to do some consulting.
Weldon: Plan ahead there?
Colby: Yeah. The measurement area looked like it would lend itself quite nicely to doing that. I actually applied for Bill’s role and was a successful candidate. In 2013, I left my leadership role and went back into measurement full time and remained there as the measurement specialist for the AER up until 2019 when we finally cut our ties and I went out and started to do some consulting.
On the consulting side, I’m basically doing the same work as what I did with the regulator just on the other side of the fence. Really, what does that mean? I help clients gain and maintain compliance if they find themselves offside with some of the measurement and reporting requirements.
I offer a service where I’ll go in and review a company’s measurement setup and the reporting setup from a high level, which generally involves connecting measurement schematics and then making recommendations on how they may be able to re-delineate their facilities, which were to produce their calibration proving costs over time.
I can make some recommendations on where they can take advantage of what we call the exemption by exceptional opportunities in Directive 017.
For example, base requirements for approved frequency on an oil meter. That delivery point accuracy is monthly, but there are circumstances where you can extend that frequency out to quarterly or even every six months depending on how stable the meter factor has been in previous proofs. Those types of opportunities.
Sometimes companies couldn’t meet compliance and I would prepare site specific measurement applications for them and steward that through the regulator to approval. I do provide some training on Directive 017 for each section. Actually, I have a contract with the Saskatchewan Regulator where I train their field inspectors on Directive 017.
Finally, I offer some Enhanced Production Audit Program field services around the evaluation of controls and measurement inspections as well. We’ll talk a little bit more about EPAP later on.
Weldon: That’s a lot of interesting stuff there. You’re right. There are several things you breezed over there we’re definitely going to have to talk more about. Before we do that, can you give us, let’s call it, a minute summary of how the regulatory bodies in Canada are organized?
You fill out ERP. Tell us what that is. Tell us where they operate, what space they operate in, and then talk to us about measurement Canada. What’s done here in the States, we hear about measurement Canada, but we don’t really know what it does either. What’s the cliff notes version?
Colby: Up here in Canada, each province has jurisdiction over their mineral rights, oil and gas being some of those mineral rights. Which means that they have the authority to exploit and develop as they see fit. Each province, generally speaking – British Columbia, Alberta, Saskatchewan, Manitoba – will have an energy department.
They will have put in place regulations that describe how oil and gas is to be explored for, how it’s to be produced, how it’s to be measured. That’s done at a provincial level. Measurement Canada, on the other hand, they have a broader focus.
They tend to focus more on measurement transactions that involve commercial interests or retail interests. For example, metering propane coming out of the gas plant because that is going to go to a commercial or retail destination.
That will be a meter that’s under the jurisdiction of Measurement Canada and has to be maintained, improved, and calibrated to their standards. The other area where Measurement Canada gets involved in the upstream business, and maybe more so midstream and downstream, is the meters that are connected to pipeline infrastructure.
If a pipeline in Canada crosses a provincial border or an international border, those pipelines are regulated by Measurement Canada, and they have to adhere to those standards rather than the provincial ones.
The other area where Measurement Canada gets involved in the upstream business is the maintenance of the national standards. For example, proven equipment, calibration equipment has to be calibrated to a national standard, and Measurement Canada will maintain those standards.
Every so often those calibration equipment and proven equipment, has to be calibrated to that Measurement Canada or national standard.
Weldon: You’re saying a lot of things there that are foreign or maybe not foreign, make a standoffish here in the US. Here in the US unless it is on federal or Indian lands, here in the US the regulations over measurement, I’m not going to say they’re not as existent, there just aren’t a lot of them, right?
Down here in the US between private parties that is dictated by contracts or by tariffs. On the midstream side, the EMP side does business with a midstream company gathering and processing their gas, even at the prostate pipeline within a single state here.
That’s very much a contract area where the federal government doesn’t get involved in. Here, the Department of Interior Bureau of Land Management, they have oversight over rights, mineral rights, from federal lands and from certain Indian nations.
Otherwise, we don’t think that regulations and measurement go together. Tell us how that differs there in Canada.
Colby: In Canada, on indigenous or Indian lands, you would think that Measurement Canada requirements would apply there as well as federal lands. Now, in the case of Indigenous lands, the federal government has created a department called Indian Oil and Gas Canada, IOGC.
They are staffed with federal employees, and their mandate is to act as a fiduciary, if you will, on behalf of the Indigenous peoples. In other words, they oversee the exploration, production, and disposition of oil and gas assets on Indigenous lands.
It just so happens that depending on what province those activities might be taking place in, they tend to defer to the requirements of the provincial regulator. Now they will have their own measurement specialists and their own auditors to audit activities to make sure that things are being done properly.
In the case of indigenous interests, it’s the federal government that oversees those interests on behalf.
Weldon: Is there a separate set of rules or standards that apply on those lands, or is it just a separate group monitoring and enforcing it?
Colby: The rules that apply tend to be the rules that have been put in place by the province. The oil and gas measurement requirements in Alberta, outside of Indigenous lands, would be the same requirements that apply on Indigenous lands.
The federal government will have auditors that will audit the activities to make sure that the oil and gas companies are complying with those provincial requirements.
Weldon: Very different from what we see here in the US. Here, those two private transactions between parties, that’s all really governed by what the contracts say and what industry standards are referenced there. That specifically measures the language you put out.
To us, it’s when we get on BLM managed properties that we all of a sudden have a slightly different set of rules. For the most part, BLM adopts our existing industry standards and regulates to them. They just focus on different areas.
Now, I know there’s another area where there’s a lot of difference between the US and Canada too. That comes to who is the custody transfer party in measurement? Here in the US where we have an oil and gas producer, it’s the people that punch the holes.
Those EMP companies, when they’re delivering into a midstream gathering and processing company, a gathering pipeline, or maybe the gatherer actually goes all the way to the wellhead with the pipeline. Here, that midstream gathering and processing company is almost always the custody transfer party in the transaction.
I think that’s a little different where you are, isn’t it?
Colby: There’s some similarities, but there are some differences. If we use the example of a gas plant, which could be considered as a midstream type facility. The custody transfer measurement that takes place there would be on the disposition side of the plant, where all of those processed gasses and LPGs and NGLs are sold.
In those cases, it’s the midstream that would do that custody transfer measurement. That’s not too different than it is in the United States. The interesting thing, though, is that it’s not uncommon, up here in Alberta and the other provinces, for the upstream producers to actually own the midstream facility.
In other words, they can own the wells feeding into the plant, and also own the plant itself. That might be a little bit different here than in the US. It might be a little bit more unique down there or a little rare to see the upstream companies own the midstream facilities.
Weldon: I think we broke that here in the ’90s. We said you can’t be involved in all aspects of the industry.
Colby: Now, the interesting thing up here, just a little bit of a side dish, from the regulator’s perspective, the regulator doesn’t get into conversations about custody transfer measurement accuracy.
They have a level of accuracy called delivery point measurement accuracy, and it tends to be measuring points that we call royalty triggers that require that level of accuracy. It’s the most accurate measurement required by the regulator.
Now, typically, all custody transfer points are royalty trigger points, but for example, for oil, the delivery point measurement accuracy requirement or uncertainty requirement is plus or minus one half a percent. That’s the accuracy required at the loyalty trigger points.
Now, custody transfer measurement up here, I think it’s very similar to in the United States, where it’s a contractual type of transaction between the seller and the buyer. Those two parties set the terms of that custody transfer agreement, including the accuracy of the measurement.
Colby: Up here, it’s not uncommon to require 0.25 percent uncertainty on an oil custody transfer measurement, and maybe around 1 to 1.5 percent for gas. Delivery point measurement requirements set by the regulator, as I mentioned, is half a percent for oil.
For gas, it’s plus or minus two percent. You can see the accuracy requirements set by the regulator are not quite as tight or strict as you would normally see in the custody transfer agreement.
Now, if we look at an example of a proration oil battery that is connected to a sales pipeline via LACT meter, that LACT meter is going to be owned and operated not by the operator of the upstream battery, but it will be the pipeline company that owns and operates that and is responsible to make sure that it’s proven on required frequency and so on.
Now, that would be very similar to the setup in the United States, as I understand. What is a little bit different, though, is if that facility, that battery, also receives trucked in production from single well batteries in the area. The proration oil battery that has slow line production from wells can also have what we call receipts that are trucked in from single well batteries.
In that case, the battery will have a truck offload station that usually consists of Coriolis meter, along with a water cut analyzer, generally microwave. This is typically a measurement point that requires delivery point measurement accuracy of 0.5 percent.
The reason that requires that level of accuracy is because those metered volumes are kept whole for reporting purposes. It’s like a royalty trigger point for the trucked in receipts, and therefore they have to be measured accurately. Not a custody transfer point, but it requires the same level of measurement accuracy by the regulator as the custody transfer point would have.
Weldon: That loosely correlates to allocation measurement here in the US. We do have sites where we commingle from truck offloading with pipeline crude, but generally, in the US, what we would call that allocation measurement.
Getting back to the royalties paid to individual leaseholders, that generally falls into some of our lowest accuracy or quality measurements here. I say generally. That’s not going to be the case with all companies. Generally, that’s the low end of our measurement spectrum more often than not.
Now, I want to shift gears a little bit. When we talked a week or two ago about potentially doing this podcast, there’s something that I had only heard just the tiniest bit about, but you talked about it quite a bit in detail. We discussed it some. Talk to us about EPAP in Directive 076. That’s something that is pretty foreign to us in the US when it comes to regulation and oversight of measurement.
Colby: Certainly, we can do that. Be happy to. EPAP, another acronym. It stands for the Enhanced Production Audit Program. This was a production audit approach implemented by the then Energy Resources Conservation Board back in 2011.
It really is based on Sarbanes Oxley and Canadian Sarbanes Oxley financial auditing and reporting, where the focus is really on a company’s business processes, controls around those business processes, and evaluations of controls. Then doing a certain amount of evaluation and controls each year, and then reporting what the results of those evaluations are.
Before I get into any more explanation about EPAP, maybe I can back up and give a little bit of a history as to what the driver was to actually move in that direction. In the old days, which was prior to, say, 2011, the way the Alberta provincial regulator conducted production audits on upstream oil and gas facilities was by a method of what we called the substantive audit.
Really, what that entailed was the production audit team sitting down and identifying an audit candidate facility judgmentally. In other words, they would look at higher risk facilities and facilities where they suspected there might be measurement problems. It always tended to be the higher throughput facilities, the more complex facilities, and so on, so the audit candidates were picked judgmentally.
Once they had picked an audit candidate, they would phone up the operator of that facility, say, it was a multi-well portion oil battery. They would inform that operator that they were going to conduct an audit on that facility.
What the audit typically consisted of was one of the production auditors visiting that facility for a number of days and going through it very thoroughly. Pretty much looking at every meter to make sure it was located properly, installed properly. The preventive maintenance was carried out on frequency, the calibrations approved.
Weldon: That’s very much like our concept of an audit here in the US.
Colby: You bet.
Weldon: Pick facilities that you have the most interest in, typically the ones with the most risk, grab your magnifying glass and your proctoscope, and go to work.
Weldon: That’s our concept. Tell us how EPAP differs.
Colby: Before I get there, let me just finish. I’ll try to speed it up. Anyway, after the field or site inspection was done, the auditor would then request all of the source measurement documents for the month the inspection happened.
Then they’d re-perform all the production accounting work to come up with the volumes that should have been reported into the volumetric database that the province had created called Petrinex, and then they would compare the results, and invariably, there were findings.
The really good thing about that approach was that it gave you 100 percent assurance of what was going on at that facility for that particular month.
Weldon: On one facility for one month.
Colby: Yep. Unfortunately, those types of audits are very labor intensive and take a long time to do. As such, the production audit team could only do about 80 to 100 audits per year.
Weldon: Let’s not forget the guy being audited got an advance notice so that he knows to be on his best behavior.
Colby: You bet. Although when it comes to measurement, there’s not much you can do to clean things up before the audit happens. With other things, perhaps. Anyway, you got 100 percent assurance what’s going on in that facility for that particular month. Now, the downside of that approach is that it’s very labor intensive. You can’t do very many audits.
At the time, when only 100 audits can be done per year, in any given month, there were up to 50,000 facilities reporting production into that Petrinex database. The coverage was not very high. In 2004, the Alberta provincial auditor visited the regulator, ourselves and also Alberta Energy. They gave both of those government regulators recommendations.
Now, before I go on, I’ll just explain that Alberta Energy is part of the Department of Energy from the Alberta government that oversees the Mineral Tenure Act. In other words, they sell the mineral rights, and they’re also responsible for setting up and collecting royalties. They have a very vested interest in the accuracy of the volumes that are entered into Petrinex.
The auditor general in 2004 said to the AER, “We’re not suggesting that the data in Petrinex is not accurate and complete, but you’re not doing enough production audits to ride the level of assurance to give us a comfort level that the data is accurate.” In other words, doing 100 audits per year in a population of 50,000 facilities gives a very low level of assurance.
They gave the recommendation to the AER to come up with an audit approach that would provide the level of assurance required by Alberta Energy. Alberta Energy was given a recommendation by the auditor general to tell the AER what level of assurance they need.
Of course, they never did, but we assumed if they ever get around to telling them this, they’re going to tell us they need high assurance. We concluded we had to develop an audit program that delivered high assurance. First thing we looked at it was, why don’t we just increase the number of substantive audits? Problem solved, but…
Weldon: When you looked at people?
Colby: Yeah. When you look at the statistics, it meant that to get a 95 percent level of assurance, we would have had to complete 300 plus audits per year, which would have meant a tripling or quadrupling the size of the production. It was unsustainable.
The other problem with that substantive audit approach is that it was very reactive. What I mean by that is that oil and gas companies could simply sit back and wait for the regulator to tell them what was wrong, and then tell them to fix it. It wasn’t really proactive or promoting continuously…
Weldon: Yeah. I can see that.
Colby: Anyways, then we looked at the methodology of financial auditing and reporting specifically, SOX and C SOX, which is Canadian SOX, and we asked ourselves a question, “I wonder if this type of approach could be adapted to a production audit environment for upstream oil and gas facilities?” We thought that it could be.
We went and we hired PricewaterhouseCoopers as a member of consultants with that type of experience. We hired Corvelle Consulting, Yogi Schulz, to be the project manager. We took three years to develop EPAP, the Enhanced Production Audit Program.
One thing that was quite unique is that we intimately included industry in the development of the program. That was a strategic/tactical decision. We felt that by and by industry it would be much better if they actually got to participate in the development of the program.
Weldon: That’s almost always the case, right?
Colby: Yeah, you bet. It was interesting. Over the course of the development period, we held 15 stakeholder committee meetings. During those meetings, industry, and we logged all this, they made 115 recommendations for improvement to the program, and we were able to act on 113 of them.
Weldon: That’s a pretty neat process. The risk of hurrying you along, which I’m going to hurry you along, let’s jump into the meat of how EPAP actually works on a routinely basis.
Colby: That’s exactly where I was going to go next. There’s a few pieces to EPAP. The first one is evaluation of controls and reporting on evaluation and controls. In the program, upstream oil and gas activities have been divided into what we call reporting themes, and there’s 14 of them.
A reporting theme could be the creation and maintenance of measurements, schematic diagrams, operation of metering equipment, proving and calibration frequencies and methodologies, gas well testing, oil well testing, EFM performance.
We’ve created these 14 reporting things that oil and gas companies are required to build business processes, first of all, that ensure compliance to the Directive 017 measurement reporting requirements. Then they’re required to create controls and operate controls to make sure that those business processes are executed as they’re defined. That’s the first piece.
The second piece then is that oil and gas companies are required to do a certain number of evaluations of controls each year and report the extent of the evaluations of controls that have been performed, and the results or the findings of those evaluations of controls.
When we first introduced this here in Alberta, a lot of the terminology was quite foreign to oil and gas production people. For companies that had internal audit departments, this is old stuff. For folks that were involved on the production side, this is all very foreign.
Weldon: In all the terms, you’re usually going to be foreign to me, except I’ve worked with SOX controls from the financial side as they affect measurement.
Colby: Just quickly an example, what would be an example of a business process? A business process would be the steps that you go through, for example, to conduct a successful proof on a meter. There’s a number of steps that you have to complete sequentially to do a valid proof and to convince yourself that it’s valid.
Then once you’ve got the business process defined, then you will develop controls to make sure that that process is executed as defined. Control might be, maybe each year, we’re going to witness the prove technician actually conduct at least 10 proves so we know that he’s doing it correctly.
Another part of the control can be, we’re going to have somebody in our operations group review each one of those prove reports and look at the data that’s contained on that report to make sure it looks reasonable. That of the five runs are all within the required tolerance, we’re getting an acceptable meter factor.
Another part of the control can be if the meter factor changes by more than X percent, we have to dig further and find out why that is the case. There’s valid reasons for that to happen.
Then maybe part of the control could be, we need somebody to sign off on this prove report, somebody from our operations group. We’re not just going to rely on our prove technician. This is an example of a business process and what a control might look like after that.
The operators are required to do a certain amount of evaluation of controls, both at the facility level and company level. Another aspect of the program is a requirement to submit an annual declaration that is signed by senior executives of the operating company.
Now the declaration is a predefined text. It’s one page long and it’s the same for every company. It contains things like it identifies who the senior executives are for the company that are going to sign the declaration.
It attests that the senior executives are aware of their responsibility to understand and comply with the regulator’s measurement and reporting requirements. There is an attestation that each year the company will perform an adequate amount of evaluations of controls.
Where they find that controls are inadequate or need to be strengthened, that in the following year they’ll remediate those deficiencies. There’s an attestation that each year upon completing the evaluation of controls, they will summarize the work and their assessment of the effectiveness of those controls and report that back to the regulators.
That’s another piece, and a very important piece of the program is that annual declaration submitted by senior executives.
Weldon: Be sure you put the senior executives on the line for what they claim their company’s doing.
Weldon: That’s a pretty interesting approach. When you mentioned this on our call before, I was really intrigued by it. Down here we have the concept of needing standard operating procedures that need to operate to it. This is much more than that. This is developed procedures to assure you’re doing measurement properly.
Test yourself to make sure you’re doing measurement properly, and then report that you’re doing measurement properly. Then put the guy in the corner office on the line if someone finds out you didn’t do it right.
Colby: That’s right.
Weldon: As you mentioned in a call earlier, it is very much in line with how SOX financial controls work here in the US. That’s pretty interesting stuff. It’s a concept that we need to look at a lot harder in the States. We have companies with SOX controls over measurement, but they’re generally very granular over specific areas and they’re not as all encompassing as what you have here.
Colby: You bet.
Weldon: This has been some super information, Colby. I wish we had an hour and a half to go. I’m going to have to wrap this up pretty quick, though. Is there anything you want to say before we wrap it up?
Colby: Can I just maybe give you a couple of more sentences on EPAP?
Colby: The decision to require a senior executive’s sign the declaration and submit it, that was a very strategic decision, and it really resolved what we observed when we were doing some stand up audits. We observed that senior executives weren’t always aware of what was going on measurement wise and that contributed to measurement mistakes and reporting mistakes.
We also observed that if senior executives weren’t all on the hook, so to speak, every company has a fixed budget for what they’re going to spend each year, and we found some companies would rather spend that money on drilling another well rather than keeping their measurement.
Knowing folks at that level, if they’re going to sign something, they’re going to want to make sure that there has been some work done. I’m just going to take another couple of seconds and talk about the advantages of this approach.
The first advantage is that it provides the coverage of audits across all facilities in the province that report into Petrinex. It gives you that higher level of assurance.
The other really important thing is that this is a proactive approach that encourages continuous improvement at the operating company level rather than the old approach, which was very reactive, and we didn’t see any improvement at all in companies. Anyways, that’s really the other things I wanted to mention.
Weldon: Again, I certainly appreciate it. What I would sum up with and say, is that compared to our approach here in the US, there’s a lot of benefits to what you’re talking about here. The overall, just as y’all tried to implement and did successfully implement, it sounds like. You’re increasing your overall confidence in what’s being done out there in the world.
I would not be surprised if you get a call or an email or two from folks on the South side of your border asking for more information on this. We will have all your information up on the website, Colby.
It takes us a few days to up the episode, but we’ll get a transcript of this up here. We’ll get your LinkedIn contact information on there. If folks want to reach out to you, they’ll know how to find you. How does that sound?
Colby: That sounds excellent, and I appreciate that, Weldon. Certainly, I’d be happy to share any information I can about EPAP with folks that have questions.
Weldon: I certainly thank you for your time here. It’s a lot to think about, Colby. You take care. Have a great one, Colby.
Colby: Thanks, Weldon. You take care. It was a pleasure.
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