LDCs Really Are Different!

My career has been heavily pipeline transportation focused – hence the book on pipeline transportation! In the last several years I have been working more with Local Distribution Companies (LDCs). While I worked in the pipeline world, I had always considered LDCs as a flavor of pipeline, just like intrastate pipelines, midstream, and interstates are pipelines.

Most LDC’s accept nominations! Doesn’t that make them a pipeline?  Not really!!

All natural-gas LDCs are pipelines in the literal sense. They are physical pipelines in the ground that are used to distribute natural gas. Some LDCs come closer to acting like an interstate or intrastate pipeline because of deregulation – in the instances where they are required to support transportation on behalf of others – such as marketers and shippers.

Acting as a pipeline is only one of the many services that LDCs perform. There are a host of others.

This is the first of a series of posts on LDCs. I thought I understood them. I now know that I have a lot to learn from them.

The Aging Workforce in Energy

Cycles in business

I’ve noticed an interesting trend among my peers lately. They are retiring! I’m not ready to retire, I’m still having a lot of fun. But, as companies change ownership and leadership, others get packages and encouraged to retire.

This could have a huge impact on our businesses!  So many companies that I work with send people just like me to the key decision-making meetings.  Where are the younger staff that are being groomed to take our positions? I was fortunate, 20-plus years ago, to be brought into the heart of some of the big changes that our industry was going through. At that time, the groups were made up of a mix of young business people like myself, who had good experience, though not deep, plus senior executives with deep knowledge. We learned so much from those senior executives, so that when they retired, we were equipped to step up and fill those shoes. But I don’t see most companies, today, sending those more junior staff into the decision-making processes along with their senior staff. They are still sending the senior staff but only sending one person and not growing someone to take that person’s place.

Yes, there is a cost involved to send two or more people instead of one. But there is a longer-term cost in only sending one person – the company isn’t growing a future generation to take the place of these senior staff. This isn’t true of all companies. I have worked with a few who bring the young people into the discussions with the senior staff, but there are still more seniors in the room than there are juniors.

And yes, I agree, that the younger staff of today are not the same breed that we were 20+ years ago. I think some of those people still exist, but they might be a little harder to find and a lot harder to retain. In recent years, I sent one of my employees to NAESB meetings, technical meetings for which he was well prepared. When he came back from the meeting he told me that if he had to go to those meetings again, he would quit!  What? I agree that it is difficult to work in a group such as NAESB because there are such long established procedures in place and so many long term relationships have been established. But don’t give up on the first try! Stick with it and make it work for you. Another associate, through NAESB, picked a successor to be trained up as a replacement upon her retirement. The person kept being a no-show at scheduled meetings and then claimed to not understand the process.

When I got started in NAESB, I already had 10+ years of industry experience and it was a tough organization to be a part of. Any organization that tries to build consensus on business processes among over 100 different companies is going to have some tough discussions! But the process works! During that time of getting started in NAESB, was also at the beginning of NAESB. To get all of the work done, many of us worked multiple 16+ hour days. Some of us even worked some 24-hour days. We did whatever it took to make the process successful. We need a new wave of this type of workforce in the gas industry. People who will work hard and are passionate about doing a good job and creating a better industry. We need to find those people, retain them, grow them, and prepare them for the future of our companies.

The question then becomes – what are these young people looking for in a company and how do we keep them? Is it benefits? Is it “work-life balance”? Benefits in companies are not the same as they were 20 years ago – and when I began in this industry I knew that these companies would grow ME as a person while growing me as an employee. Is this what recruits are looking for today? Or is it something different? We need to know what the current generation requires. We need to plan for succession.

NAESB? Nahhhzbe? Nazzz-bee? Nayz-bee?

If a telemarketer calls me and they call me Ms. Mooon-son or Ms. Mun-ster, then I know they definitely don’t know me!!

The same thing happens with NAESB!

The ways that people pronounce “NAESB” are hilarious! NAESB, in case you don’t know, stands for the North American Energy Standards Board. Anyone that actively participates in the organization pronounces the term as Nayz-bee – with a long A. If you want to sound like an insider, say it the way the insiders do.  Try it out. . . . Nayz-bee – with the long A sound. Now you can sound like an insider, too.

If you want to be a real insider, check out the web page at NAESB.org and consider joining the organization. There is a lot to be learned from then.

All the Cards on the Table regarding Gas-Electric Harmonization

All the Cards on the Table regarding Gas-Electric Harmonization

The gas industry, through the North American Energy Standards Board (NAESB) has been working on changes to the confirmations and scheduling process since mid-2015. This issue has become a conflict of FERC direction, NAESB scope, electric generators, pipelines serving electric generators, and multiple industry participants, all in the name of progress.

The FERC has been working on issues related to Gas-Electric Harmonization since 2012.  In 2015, the FERC issued Order 809 after NAESB had increased the number of nomination cycles in a day from four to five available cycles, as a Gas-Electric Harmonization solution.  Order 809 instructed the industry, through NAESB, to look at further ways to gain Gas-Electric Harmonization efficiencies, particularly in the areas of confirmations and scheduling, and NAESB has been working on it ever since.

FERC Chairman Bay sent a letter to the North American Energy Standards Board (NAESB) in October regarding the status of NAESB’s work on Order 809 deliverables. In the letter, he charged NAESB to complete the current body of identified work by March of next year.

The FERC has historically utilized NAESB and the NAESB process to encourage the industry to solve problems on its own and this has been a successful relationship. The topic of Gas-Electric Harmonization seems to have taken several very slow baby steps without hitting the real issue that the FERC wants solved.

There are a lot of reasons that factor into this slow progress. 

  • Gas and electric industries have very different commercial arrangements and operational environments and, correspondingly, work in a very different way.
  • The FERC governs interstate transactions. On the gas side of the house, that means interstate pipelines. A small percentage of gas-fired electric generation supply is provided directly from interstate pipelines.  The majority is provided by a local distribution company (LDC) or utility, over which the FERC does not preside.
  • The significant solutions require policy changes or additional pipeline service offerings. These cannot be solved by NAESB. They must be solved by the FERC and the pipelines. Then, if there are standards to be written to insure consistent implementations, NAESB can write those standards.
  • NAESB participants, historically, expect standards out of the NAESB process for FERC adoption and, therefore, the standards are expected to be written directed at interstate pipelines. LDCs and gas utilities may have adopted portions-of or variations-of NAESB standards, but they are not required to be NAESB compliant.
  • The actionable items have been small actions from an external point of view. The effort to implement those small actions has, in some cases, been significant. NAESB participants determined that some recently implemented changes needed to be in place for a measurable time before determining if additional changes were needed.


1              The Gas and Electric industries work differently

Some of the differences in the operational considerations of gas and electricity are common points of discussion.  It is generally accepted that electricity performs on an ‘on demand’ basis while gas flows on an ‘as scheduled’ basis.  It is generally thought that electricity is changed in ‘real time’ while gas flow is changed with prior planning.  Electricity changes and scheduling occur on an hourly and sub-hourly basis.  Gas plans are made on a day-ahead basis and changes can be made up to four times per day.

There are also common factors.  One of the common factors is that both industries charge their commercial customers on a demand basis.  The way that the demand is charged can be very different, but the premise is very similar.

In the electric industry, commercial customers may have a demand meter. This demand meter measures the highest level of usage over a period, often a year, and charges that customer a demand charge, based on that highest level of usage, for the subsequent year.  The demand charge is to compensate the electric service provider for having that high level of capacity available on-demand at any time that the customer needs it.  The electric generator must have the capability to deliver, at any given time, the sum of all the peak demands for these customers and, therefore, charges for that service.

In the gas industry, the commercial customer has a contractual quantity and, for firm service, is charged a demand charge on a demand quantity that is the most the customer can take daily without incurring overrun charges. This negotiated quantity is a quantity that the pipeline can guarantee the ability to delivery daily and the pipeline charges a demand charge for that deliverability.

Some electric generators, in NAESB facilitated meetings, have indicated that they do not want to contract firm service with gas pipelines because of the cost and because they cannot commit to that long-term demand quantity. But those same electric generators are charging their own customers demand charges that are determined in a slightly different way.

Can firm gas contracts be written to utilize some of the terms and flexibility of the electric demand mechanism to make firm gas contracts more attractive to electric generators?  Can pipelines design a firm gas contract for electric generators that charges a demand rate based on their peak gas usage during a period?

To do this, the FERC may have to re-evaluate the terms used to determine the viability of construction of additional pipeline infrastructure.  The current methods may not support this type of change to the existing firm contract policy terms.

2              The FERC governs interstate transactions

Most gas supply used by electric generators is delivered by LDCs and utilities. The FERC does not govern LDCs and utilities that provide transportation services. Interstate pipelines are the supply, in many cases, for the LDCs and utilities and, therefore, effect the service that can ultimately be provided.  However, the interstate is not the ultimate delivery pipeline to the electric generator. If the LDC or utility, providing transportation service, does not adopt the standards that NAESB develops and the rules that the FERC imposes on the interstates, then the solution for the electric generators becomes limited by those providers.  The interstate pipeline services cannot solve this when there are subsequent, downstream services that diminish the capabilities of the interstate.

For this effort to be effective, all transporters, whether they are interstate pipelines, intrastate pipelines, LDCs or utilities, must provide peer services that do not diminish the ultimate service to the electric generator. Otherwise, the efforts become ineffective.  States must pick up the baton and implement the NAESB standards in their jurisdictions for Gas-Electric Harmonization to be truly effective.

3              Policy changes are needed

By assigning the task to NAESB, the FERC either presumes that there are no policy changes needed or expects NAESB to identify the policy changes that are needed.  NAESB, to date, has not identified any policy changes that are stumbling blocks to progress.  This is, in most part, because NAESB is responding directly to the FERC’s request and has not identified an instruction to “think outside the box” or “find an ultimate solution.”

For the significant changes to occur, the ones that will show substantive value in Gas-Electric Harmonization, the FERC will need to make policy changes.

4              NAESB standards affect all industry participants

The statement that “NAESB standards affect all industry participants” causes an “of course” response to many industry participants.  There is an equal group that responds “No, they don’t.” NAESB standards apply to all industry participants.  Depending on the participants’ role, the standards may apply in different ways.

Because the FERC’s adoption of NAESB standards applies only to Interstate Transporters, some participants have come to assume that the standards only apply to those Interstate Transporters.  This is incorrect.

In October 2016 NAESB BPS GEH related meetings, it became apparent that one of the breakdowns in discussion of changes to the NAESB datasets involved the LDCs’ implementation of NAESB standards.  While many view the LDCs as Transportation Service Providers (TSPs), states have not historically required LDCs to implement transportation services as a NAESB defined TSP role. Therefore, many LDCs have implemented significant variations to the NAESB standards such that, if NAESB implements the proposed changes that have been identified in the Gas-Electric Harmonization process, the LDCs will be negatively impacted.

These issues are not because changing the NAESB standards would impact LDCs.  These issues are because LDCs have implemented NAESB standards in very non-standards ways.  Because of these non-standard implementations, changes to the existing standards will have a negative impact on the LDCs.

Non-interstate transporters, including LDCs need to recognize that NAESB standards apply to them.  If they need changes to the NAESB standards, then they need to request those changes. This will protect them from unintended consequences when changes are made to the NAESB standards in the future.

5              Time will identify the benefits of previous changes

There were additional items identified for possible standardization or changed standards as part of the NAESB GEH forum meetings related to Order 809.  There was one hitch.  Participants did not have enough experience with the impacts of the NAESB 3.0 changes, which were implemented in April 2015, to determine if additional changes would be warranted or effective.  NAESB determined to delay examination of these items until a business cycle of one year had lapsed so that the benefits and shortcomings of the NAESB 3.0 changes could be recognized.

Time, however, marches on.  The electric industry’s dependence on natural gas for generation reliability is moving forward at a fast pace.

Waiting for the previous decisions to prove themselves may cause other unintended consequences.

What are the real issues that need to be solved?

Each of the issues describe below is a high-level summary.  A full discourse on each of these subjects would require a ten-page introduction to describe the full issue.  This is a summary.

1              Electric generators need to know that gas will be available when needed. This means that gas needs to be available any time, any day, on demand. Electric generators have already increased their reliance on natural gas for electric generation and more units are scheduled to be moved online for gas fired generation.

Gas providers, as described above, work in a different operational paradigm than electric generators.  Additionally, the permitting process to build additional gas deliverability does not line up with the expectations of electric generators.  The electric generator’s compensation model discourages them from engaging in long term firm service agreements.  The gas provider’s construction permitting model requires long term firm service agreements to justify building additional pipeline capacity.  This is an area that the FERC must address outside of the NAESB process.

2              The gas providers that can have the most impact on successful gas supply to electric generators are the Intrastate pipelines and LDCs. FERC regulations and mandating of NAESB standards by the FERC does not apply to Intrastate transporters or to LDCs offering transportation services.

States need to adopt NAESB standards to ensure across-the-grid reliable delivery of natural gas.  Many states have implemented reliability standards within their own states but those standards do not recognize that the supply of gas, in most cases, comes from interstate pipelines that work under FERC rules.  Some states have imposed requirements on their pipelines (Intrastates and LDCs) that contradict the requirements imposed on the interstates and cause conflicts in the exchange of information.

3              Firm service agreements are not attractive to electric generators. Firm service agreements, traditionally, identify a quantity of gas to be delivered, on a daily-basis, for a period-of-time.  That period-of-time may be less than one month or more than five years.  These are negotiated as part of the service agreement.

The demand quantity assumes a constant flow throughout the day, though a few pipelines offer the ability for a shipper to shape their nominations within the day. There may be allowances for seasonal variations, where the demand quantity may have different quantities at different times of the year. This demand quantity is structured much like the peak-demand quantity that electric generators charge their commercial customers and, it works in a similar fashion. There is an opportunity to re-define the contracting of demand quantities, in natural gas transportation contracts, so that it aligns with the demand quantities that electric generators use for their customers.  These re-defined services may apply only to electric generators and the service providers that transport for electric generators. This opportunity, however, is hindered by the current definitions of the demand quantity, its defined purpose and its use in evaluation of pipeline capacity construction permitting.

4              Interstate pipelines are required to offer capabilities for electric generators to make changes on the pipeline throughout the gas day, on an as-needed basis. The mechanisms that pipelines have used to solve this problem varies significantly across pipelines and can create grid-wide synchronization issues.  Are those the issues that need to be solved?  No one participating in the NAESB process has voiced this as a concern.  Does that mean that there is no problem? Does it mean that generators don’t want the FERC to change the way ‘their’ interstate pipeline serves them?

Pipeline services can solve some of the Gas-Electric Harmonization requirements if those services are available on each pipeline in the supply chain of the customer.  These services are being discussed as part of the NAESB process as options that a pipeline, as a transportation service provider, may offer. There is currently no requirement for these services to be offered.  And the services being discussed are offered on some pipelines today, but not all pipelines. Note that these services are not directly related to the instruction of Order 809 to find efficiencies in the confirmations and scheduling processes, but they have been identified as items that could solve some of the issues that arise during the confirmations and scheduling process.

The ability to create a shaped-nomination or profile-nomination on a pipeline has value to the electric generator by allowing the generator to identify an hourly flow rate to the pipeline. This gives the pipeline the ability to schedule the entire day of gas and identify any potential hourly constraints that may arise. These shaped-nominations, where currently in use, give shippers the ability to change the projected flow on any of the five existing NAESB nomination cycles without requiring that pipelines schedule the entire pipeline more times during the business day.

Best efforts nominations, offered by some pipelines, allow shippers to nominate between the NAESB defined nomination cycles to have incremental changes to gas flow.  This service provides space-available changes outside of the standard cycles which means that pipelines need to have rules or practices in place to deal with the possible inability to confirm the flow and the possible resulting imbalances. When this service is trued-up at the subsequent standard cycle, the imbalance risk can be minimized.

Both above described capabilities should be defined as services, within a contract type, on a pipeline. They need to be defined with boundaries, limitations, and corresponding service related rates, if applicable. The pipeline should have the option to limit the availability of this service to electric generators or those service providers specifically delivering to electric generators.

If the FERC wants to get creative to solve this issue, then it should look at then the concept of first-come-first-serve should be examined, within a service level, that permits pipelines to schedule capacity throughout the gas day, after an initial timely scheduling cycle.  This would invite the opportunity for real-time confirmations and real-time scheduling on a net-change basis.  This would require acceptance of newer technology, such as XML transactions rather than EDI transactions, but it could be done.

5              What can NAESB solve in the confirmations and scheduling processes?  Honestly – not much!  NAESB can fine tune the business process of confirmations, and there are some efficiencies to be gained.  This is what the NAESB process is working on today, although there has been resistance to change voiced because of the additional issues described above.  Cleaning up the confirmations process will gain efficiencies in timing and, if a few more changes are made, can add volume surety to the confirmations process.

As far as scheduling goes, there are not any changes that NAESB can make. Pipeline scheduling processes are distinct for every pipeline.  This is because the physical construction of the pipeline is a huge factor, the operational constraints for each pipeline are different, the operational focus of the pipeline is a huge factor, the services offered by that pipeline must be considered, and, of course, the customers and the quantities they elect are factors.  Each pipeline’s scheduling process and scheduling priorities must be determined by that pipeline’s factors and that pipeline’s tariff.  There is nothing that NAESB can do in this space.


NAESB can make some changes in response to the charge administered by FERC.  These changes are not going to effectuate the results that the FERC is looking for.  To get the desired results, there must be policy changes by the FERC, adoption of better business practices at the state level, and new services adopted by the pipelines.  Inside of these non-NAESB decisions, NAESB can make the necessary standards to ensure a consistent implementation plan and useable standards.

This is my opinion. There are participants in the industry that NAESB as the source of additional solutions that could solve these problems.








Confirming Natural Gas Nominations

Confirming natural gas nominations

Is it better to confirm at a shipper level or a nomination level or something in between?

The level of detail of confirmations can cause chaos on a pipeline during a process that has a very finite window.  Confirmations occur at a location where gas is received onto a pipeline or delivered off of a pipeline. The confirmation takes place between the interconnected parties at the location. One of the parties requests the confirmation and the other party responds with the confirmed transaction quantities.  If the parties cannot agree on which party will be the requester and which will be the confirming party, then both parties will issue the request and both parties will respond.

The party requesting the confirmation determines the level of detail in the request.  The confirmation dataset allows the request to contain, minimally, one shipper – either the upstream or downstream party, depending on direction of flow.  The dataset also allows the confirmation requester to include shipper contract, upstream and downstream contracts, associated contracts, package ID and upstream and downstream package IDs.

There are a lot of variables in the confirmation.

On one pipeline, the pipeline may receive a request for confirmation, for one location, at the shipper level; for a second location, identifying the shipper, shipper contract, and upstream or downstream contract; and for a third location, identifying the shipper, shipper contract, upstream or downstream contract, package ID and upstream or downstream package IDs. In the third example, the interconnected party is confirming at an equivalent to the nomination level.

Let’s use the upstream pipeline as our interconnected party for an example.  If that upstream pipeline confirms at the nomination level, then the confirming party has told us which nominations to cut and which to keep whole based on our pipeline nominations.  In a worst case situation, they could be cutting nominations on a firm contract that the shipper ranked as top priority and the upstream pipeline is making that decision on our pipeline. That doesn’t make sense.

Confirming at a nomination or package ID level is bad.

Using our same example, suppose we are confirming at a shipper + shipper contract – to – upstream shipper + upstream contract level.  The upstream pipeline is going to make sure that the service level on their pipeline is met first.  If their shipper (the upstream shipper from our point of view) is shipping on a firm contract, then the pipeline’s duty is to keep it whole if possible.  But the same party is delivering to the interruptible contract for a shipper on our pipeline. So the pipeline may be telling us to keep an interruptible contract whole for our shipper while cutting a firm contract.  That doesn’t make much sense either.  It is important to note, though, that this is the most common method of confirmations used today.

Confirming at a shipper contract level is bad.

Back to the same example.  Suppose we are confirming at a shipper – to – shipper level.  The upstream pipeline will total the quantities for their shipper, across all of their contracts. The confirming party will tell us the quantities being guaranteed for each of the shippers. Now we can use our pipeline tariff priorities to determine which of the shipper’s transactions are confirmed and which are cut. This means that our contract priorities are used first, so that the shipper’s Firm transactions can be confirmed first. This also means that inside of a contract, the shipper provided ranks can be used to tell us which of the nomination line items should be cut if a cut needs to occur.


Keeping Transactional Data Clean

IMG_0175 ppKeeping Transactional Data Clean

How do we differentiate between functional data and feature-related data?

We are fortunate in the Natural Gas business that pipelines, the Federal Energy Regulatory Commission (FERC) and other entities are always finding a new way for us to conduct business. New technology, new services, new market drivers all contribute to this endless river of change.

To support these changes, the process is that companies will come to the North American Energy Standards Board (NAESB) with requests to add a new code value, a new data element, a new data set or even new standards to support these new capabilities in a standardized manner. This is good and this is the way the process is designed to work.

But –

Imagine you were going on a long river journey in a canoe. You would pack that canoe carefully to contain exactly what you need. Then, friends come along, with good intentions, and bring you an extra blanket, a specialized cooler, a rope specifically designed to aid in traversing portages, etc. Then the canoe that you packed so carefully begins to become unwieldy. It becomes disorganized. Now you have multiple tools to accomplish the same task. How do you solve this and get back to a manageable canoe? In my case, you’d unpack the canoe, pick the best solution for each task, re-pack the canoe and leave the excess behind.

This is where we are with the NAESB datasets today. We began with a set of datasets in 1996 that were as clean and efficient as we could negotiate. Over the subsequent 20 years, companies have made requests to add new capabilities because of their business practices or new market drivers. They were valid requests. But somewhere along the way, our datasets have become unwieldy. We now have 77 data elements in the nomination dataset alone. We cannot continue to add codes, elements, datasets without paying a price.

There are essentials in the datasets that absolutely must be there, such as the receipt location on a nomination. But we have added many elements and codes along the way that warrant re-evaluation. An example would be that we have three different data elements, as three different options, to bid a transportation rate in the nomination. Initially, I thought that the Mutually Agreed and Business Conditional data elements need to be reviewed, but now I realize that all of the data elements in all of the datasets should be reviewed. The essential elements are functional. The other elements are often features that can be identified in the pipeline business process, within service offering descriptions, or contract terms.

We need to unpack the datasets. Lay out all of the elements and codes. Determine exactly what we really need and determine what we can leave behind.

We do not want our canoe to flip over.

Standards versus Services

Standards versus Services

When does policy become an issue in setting standards?

There are many people in the natural gas industry that have big ideas on how to make our business better – myself included.  There are venues that have been made available, via the North American Energy Standards Board (NAESB) and via the Federal Energy Regulatory Commission (FERC) to present these ideas, vet them properly, and bring them to fruition.

There can be confusion on which venue to use in which situations.

If a pipeline wants to add a new service to the pipeline, then it must first get approval through FERC. Once that service is approved, if the existing NAESB standards for business process implementation do not support the service, then the pipeline can request new standards or modifications to existing standards through NAESB. Often pipelines are able to implement new services without requiring any changes from NAESB.

That seems simple and clear.

What if someone wants to require that all pipelines offer a specific service?  NAESB does not create services, pipelines create services.  And pipelines create services based on FERC policy.  In a case like this, the company needs to present their concept to FERC.  If the FERC determines that the request warrants new policy, that requires pipelines to offer the service, then FERC will issue the new policy. After that, pipelines will make corresponding changes to their pipeline tariffs defining the new service – and – if needed, the pipelines or their service providers will request NAESB to develop or modify standards to support those services.

Policy decisions are made by the FERC.

Not all pipelines offer the same services.  In such a case, NAESB will include language in the standards such as “Where a pipeline offers the service to . . . . then the following standards should be used . . . “ In this manner, pipelines can construct new services and ensure that they remain within the NAESB standards even though their service may be unique or may only be offered by a few pipelines.

Services are decided by the pipelines – the service provider.

NAESB writes standards to implement services and policy. There have been many occasions where the FERC set policy and looked to NAESB to set the corresponding standards so that the policy could be implemented in a consistent manner.  There are also many occasions where a pipeline has offered a new service and submits a request to NAESB to standardize the service.  The benefits of the service-related standards come when additional pipelines want to offer the same or similar services and can utilize the existing standards to accomplish the implementation.

NAESB sets standards for services and policy.

All of these components – services, policy and standards – work in harmony as long as we agree and accept where the lines are drawn and the limits of the scope / responsibility of each organization.

Book Update: Two important things to know in Natural Gas today

Book Update:  Two important things to know in Natural Gas today

I apologize for the long absence.  I’ve been very busy!  What have I been busy on?  That is today’s topic!

Number One: Mexico is calling!

It seems that everyone in natural gas is involved in some type of activity with Mexico right now.  The book – Contents Under Pressure has caught on in Mexico and I have spent most of the summer preparing training, conducting training and building relationships in Mexico.  I’m in Mexico City right now conducting training on the US gas business for Cenagas.  As you may know, Cenagas is the pipeline group formed out of the changes in Mexico’s gas business.  Cenagas is the pipeline formerly known as Pemex, though Pemex had a much larger footprint than just pipeline transportation.

What a great group of people to work with!  There is a vitality in the organization that just celebrated its second anniversary.  The people are eager to learn and eager to provide a good service for their country.  The initial interest from Cenagas has led to me posting a whole list of training options on the website at https://contentsunderpressurebook.com/teaching-and-training/.  Contact me to arrange training for your group or company.

Number Two:  Gas/Electric Harmonization is moving forward

The NAESB organization has adopted five of the concepts out of the Gas/Electric Harmonization Forum to move forward with in 2016.  In addition, specific standards development requests have been submitted by industry participants. These items have been added to the annual plan.  Now comes the hard part – the work of building consensus across disparate priorities and agendas to develop solutions.  The committee for development of the standards, the NAESB WGQ Business Practices Subcommittee is meeting approximately every two weeks in a combination of web-based conference calls and face-to-face meetings.

The items being addressed and the order for addressing them is as follows:

2016 Annual Plan Item 3(b)(i)

 GEH Forum Issue 22-Terminology

                Note: This Annual Plan Item will be included with each of the agenda items below.

R16003a Skipping Stone and Environmental Defense Fund


R16003b Skipping Stone and Environmental Defense Fund / R160007* FIS Global – Energy Services

Nomination of Hourly Quantities

2016 Annual Plan Item 3(b)(v)

GEH Forum Issue 36-Level of Confirmations

2016 Annual Plan Item 3(b)(iv)

GEH Forum Issue 33-Multiple Confirmation Methods

2016 Annual Plan Item 3(b)(ii) / 2016 Annual Plan Item 3(b)(iii)

GEH Forum Issue 25-Communication Protocols / GEH Forum Issue 26-Improve                       efficiency of critical information sharing

R16003c Skipping Stone and Environmental Defense Fund

 Special Efforts Nominations

R16003d Skipping Stone and Environmental Defense Fund

 Special Efforts Capacity Release

R16004 FIS Global – Energy Services

Update Nomination dataset

There are some important changes to our business practices that could come out of these items.  It is valuable for all industry participants to pay attention and participate so that all needs are met, not just some.

The Aggravation of Nomination Aggregation in the Pathed Non-threaded Nomination Model

Four-score and seven years ago – okay, really – only one score of years ago – when the Pathed Non-threaded (PNT) Nomination Model was created it was an outlier model type used by one company.  Today that model type is used by many companies and is becoming the source of a lot of interpretation.

There are problems with the way the model type is being implemented today and there are two factors contributing to this problem. We’ll look at them individually then pull them back together to find a solution.

Factor 1:

The Service Requester Contract (SrK) is mandatory on the upstream and downstream nominations of the PNT model and it should not be. Kinder Morgan, Boardwalk and Iroquois have submitted a request to have this changed.

When the model type was created, for NGPL, the NGPL representative, Mike Schisler, explained that the shipper contract (NAESB term = Service Requester Contract) had no meaning on the upstream and downstream nominations of the PNT model.  But the data set designers insisted that it remain. The compromise was that NGPL would fill that field with the service requester’s DUNS number.  That solution has worked for NGPL for many years even though many of us in the industry as well as more recent implementers did not understand the real impact of the decision. The solution implemented by other pipelines varies, is inconsistent, and provides for unintended inconsistencies.

Note that I do not believe there is any documentation in the NAESB standards or implementation guides that specifically says the SrK should be filled with the service requester’s DUNS number.  This was only an “understanding” – which adds an additional level of confusion and was not conveyed to other parties attempting to implement the model in the same way.

Factor 2:

The Service Requester (SR) is defined as the shipper or their agent.

There is one field for a Service Requester on a nomination.  My understanding has been that if the shipper is submitting their own nominations then they will provide their own identifier as the service requester.  If the agent is submitting nominations for a shipper then the agent identifier will be used in the service requester field and the service requester contract will be used to distinguish shipper rights for that agent.

Basic Math:

When we add these two factors together in the model type, you would think that we’d get 3 simple variations since both are mandatory.  SrK used + SR Agent, SrK used + SR Shipper, SrK DUNS + SR.  Not so!  What we’ve seen in the industry is that we have 4 (rumor is that there may be a 5th) variations of how pipelines use these fields to define nominations for the upstream and downstream nominations of the PNT model.

Pipeline Scenario 1:

SR = Agent, SrK = agent DUNS


I have to admit – this is the way that I thought that the PNT model should work when an agent was engaged.  I did not initially recognize the implication of this scenario.  If I, idealistically, apply the definition of the SR and then use the rule of putting the SR’s DUNS into the SrK field then the result is this scenario.

However – if you consider a group of upstream nominations at a receipt location where all of them are designated for the agent, then how does the pipeline determine which transactions belong to which shipper and how is shipper-must-have-title rule being followed?  This would be a plausible solution if the agent has asset-manager rights but not for a traditional shipper agent.  This forces the agent into what I would call an agent-level aggregation where all of the agent’s transactions at a location are aggregated under that agent and not distinguishable by shipper.

Pipeline Scenario 2:

SR = Agent or Shipper, SrK = shipper DUNS


This scenario works the way that I believe the model type was originally intended but it has to abuse the data elements in order to make the model type work.  In this scenario, all of the quantities for one shipper are aggregated at a location so that they can then be distributed among the threaded, contract-specific nominations on the other side of that same location.

If the shipper is the SR then this scenario is clean and easy, though the pipeline is still forced to repeat the shipper DUNS in the SrK field.  When the agent is the SR is where the information becomes muddy and where it becomes obvious that an additional data element, to distinguish the agent from the shipper, is necessary.

Some pipelines have solved this scenario by using the EDI enveloping to identify the agent and, then, identifying the shipper in the SR field.  This works, but it is another forced use of the data elements in a way they were not intended to be used.

Pipeline Scenario 3:

SR = Agent or shipper, SrK = shipper contract


If the pipeline has chosen to use the shipper contract on the upstream and downstream nominations then the issue of whether the party identified in the SR field is nullified.  The level of nomination aggregation has been taken to a lower, contract level, and the contract for aggregation has been identified.  This contract-level aggregation does not provide as much flexibility for the shipper, but all of the data needed to accomplish the task is included.

However, even though the SrK solves the problem, the solution should be consistent across all of the nomination models and model usages.

Pipeline Scenario 4:

Any of the above plus Threaded Nomination association


I am including this scenario because I have seen several companies implement the PNT model in this way even though the data in the transaction does not support this implementation! In this scenario, the upstream and downstream nominations are directly tied to a threaded nomination.  This is essentially a pathed-nomination in most examples where a single upstream is tied to a single threaded nomination and a single downstream, but the implementation does allow for two or more upstream or downstream nominations to be tied to that middle threaded nomination.  There is no aggregation at the contract or shipper level in this scenario because the upstream and downstream nominations are tied to an individual threaded nomination.

Again – the data in the dataset does not support this implementation.  The implementer has to create an artificial connection to tie the various nominations together. The artificial solutions that I have seen are through tracking id’s, package id’s or through the use of a pipeline-managed database internal id that is not maintained by the shipper.  This scenario would be impossible to implement using EDI in the existing dataset.

So where does this leave us?

We need a solution so that shippers know what to expect. We need a solution so that the implementations of the model type can be clean and consistent. We need to add and define the data in the dataset so that it fully supports the model type. We can continue to perpetuate some of our incorrect decisions, but, ultimately that does not buy any efficiency, it allows us to continue with bandaids as solutions.

Here are my suggestions:

1              Split the current “Service Requester” data element into two fields:

Service Holder or Shipper and


Service Holder/Shipper could either be mandatory in all cases, or conditional with a condition that it is mandatory except where a pipeline supports agent-level aggregation and the nominating party has provided an Agent DUNS. I would prefer mandatory and let the pipeline implementation determine how the shipper information is used.

Agent would be conditional – either an agent or service holder must always be provided and Agent is required if the party submitting the nomination is different than the party holding the service contract.

2              As Kinder Morgan, Boardwalk and Iroquois have requested, make the service requester contract a business conditional data element on the upstream and downstream nominations of the PNT model.  It should remain mandatory for all other cases.  It should only be used on the PNT model’s upstream and downstream nominations if the pipeline supports contract level aggregation. Otherwise, it is not used.

3              Make it clear in the nomination implementation guides that there are three levels of aggregation and that a pipeline will generally only support one of those levels.  The three levels are Agent-level aggregation (give an example), Shipper level aggregation (give an example) and Contract level aggregation (give an example).  If parties desire the dataset support additional levels of aggregation then those parties need to submit a request to NAESB for the requirements of that aggregation level to be supported.




Why data hierarchy matters in standard gas datasets

Why data hierarchy matters in standard gas datasets

When NAESB first created standardized data sets for data exchange, all of the datasets were created for EDI implementations.  EDI implementations have a natural data hierarchy to drive the data placement.  Times have changed.

As development of additional data sets has progressed, there are several gas-related data sets that do not have corresponding EDI implementation. These data sets result in a data dictionary of data elements with no instruction to the user of how the data should be placed.  There is no stated intention that this is a flat-file presentation of data, therefore it is up to the implementer to determine where the hierarchy belongs.

In case this isn’t your specialty – let’s go into a little more detail.  If you look at most NAESB datasets, there is a 3-tiered approach to the data (there are a few with 4, but the same rules apply).  The first tier, referred to as the Header, informs the two parties of who the information is from, who is to receive the information, and a date or date ranges. The second tier, referred to as Detail, may contain contract information, location information and/or a range of dates relevant to the Header. There may be multiple Details inside of one Header in the file.  The third tier, referred to as the Sub-Detail, usually contains the line-item information.  This may be location data, rate data, volumes, nomination line items or other specifics dependent on the dataset.  There are usually multiple Sub-Details per Detail.  As mentioned, there may be an additional level of detail, referred to as the Sub-Sub-Detail in some datasets.  All of this means that for one dataset, there is one Header with one or more Details where each Detail contains one or more Sub-Details.

Okay – back to the original point. If a NAESB dataset does not have EDI instructions, then that NAESB dataset does not have a corresponding hierarchy.  Let’s suppose that the dataset contains a contract and contract rates.  Without the hierarchy, I might decide to list my rates with all of the contracts that contain that rate or I might decide to list my contract with all of the rates that apply to that contract. This might seem fine because it fits the apparent business need.

Now suppose I am a marketer who does business on 60+ different pipelines and I need to record this data into my own data management system.  If one pipeline has the data presented as Date > Contract > Rate, another pipeline has the data presented as Rate> Contract > Date and a third pipeline has the data presented with all of the data elements on each row of data, then it might be impossible for me to figure out how to record this information in my system.

Designating dataset hierarchies does not need to go to the level of detail of NAESB’s previous ‘data groupings.’ It will, however, create a level of clarity for users viewing the screens and download data.  With hierarchies in place, you will be able to have an expectation of the data and where, generally, it will appear.

The problem is that pipelines have implemented these datasets without this level of direction and it will cause change, for some pipelines, to institute these levels.  The benefit is that the users of this data, the shippers, marketers, and agents on the pipeline systems, will find the data more useful.

This effort of work will not be an overnight task. It will require time and, probably, negotiation to come to a common ground.