Jamie Ormand: so? We're good. Thanks, Robert.
Okay. Good afternoon, everybody. Thank
you all for coming. My name is Jaime Ormond.
I'm a senior analyst here at the California
Public Utilities Commission in the Energy
Division. We're here in Rulemaking 1302008 to
talk about consideration, consideration for
a standard renewable gas interconnection
tariff. Come on in, everybody. So, just as
we're getting started, we're gonna do the
normal protocol, Safety and Emergency
Information. So, in case anything bad happens, we
have a meeting point, which is at Opera
Plaza, which is basically, if you go out the
front of the Commission or out the side of
the Commission, you walk down the hill, you
see the big black statue, or it's a big
black box, it's made of granite, go to the
right, and there we will reconvene in the War
Memorial and Opera Plaza. Then when we get
some signal, we'll figure out what to do at
that point. So that is our safety and emergency
information. Just so we all know, the
bathrooms are at the end of the hall, and we
have a cafeteria, Mochas, in the other building,
where we have coffee and water to keep
everybody awake. I recognize this is an
unorthodox time to meet. But we had a Commission
meeting here in the morning that we worked
with and we're here today, we have a lot of
information to get through, which is why
we're starting right on time at noon. Okay.
Jamie Ormand: So today's workshop information. We're here at the
PUC. We're starting as close to noon as humanly possible. Our call-in
number is here with the passcode. We are live broadcasting through
AdminMonitor. The website is here on the slide deck. You can find all of
this information on the CPUC's Renewable Natural Gas Website. All you
need to do is Google CPUC Renewable Natural Gas, our website will come
up, and then, you just scroll down until you find the November 14th,
excuse me, November 13th, that's today, workshop box. And again all
this information is available on the web, including some of the presentations
that we're gonna be going through today. They're already uploaded,
so we're ready to go. So this is our third meeting this year. Who
knows who this is? Show of hands. This is the third time I've asked
this question this year. So I'm hoping that the number of hands are more
than four, which is what our high number at our last meeting. Greta
Thunberg. Her motive, she's led, leaving back on another sailing a
sail boat for Europe. Today, she says that climate change is really
black or white. We're either going to stop emissions or we're not. So
bonus question, for our third workshop of the year, who's that? Hands
up, if you know Jamie Margolin our American Greta Thurnberg, the head
of the Zero Hour climate change movement. Okay, so just before we get
started, a couple of thoughts. I want to first introduced you to Rich
Sandow here. My new compatriot on the Renewable Energy Renewable Natural
Gas team. Wave. He's here in San Francisco. Next year, we'll find
him in Sacramento. Love Aseto Akofe is our new team member in L. A.
She is joining us on the Internet. You will meet her in the future. I
want to point out my intern, George O'Connelly. He does energy economics
at UC Davis. Jack Chang, my other intern there in the back. He is a
renewable energy, climate change, science and policy at UC Berkeley.
Goldman Sachs. My two interns for the day. Ask them anything. They're
here. I want to thank Tardon in the booth. I want to thank Robert
Stanford here. They make meetings like this happen. I'm showing this
slide here about teamwork and working together to create great change.
Jamie Ormand: I just want to take a moment and just remember
Edgar Hansen. He helped us put together all of our workshops
this year, and he passed away suddenly. This organization
is reeling from a great loss. And I just want to honor
him because he has been helping me do my job for seven years.
He has been helping this agency do its job for his entire
career. He's no longer with us. It's really sad. So we're
all gonna work together to make this work in his honor.
Jamie Ormand: Okay. The agenda for today. First of
all, we have our welcome and preliminary comments. We're
going to get right into the utility joint presentation
of their draft standard renewable gas interconnection
tariff, which they have been working on together
diligently for months. This is a very big deal. Our gas
utilities working together to create a platform for
the future. We're gonna have a robust to question
and answer period because I know you're all familiar
with the document that was filed on November 1st. You
read through it, you have your questions prepared, and
for those of you at home, or at your location of work
that isn't in the room, the filing is also findable
on the Renewable Natural Gas website. You could just
open it and everything that we're talking about is
available there, too. We're going to do a stretch break
after our Q&A, and then we're gonna come back and we're
gonna talk about new renewable natural gas projects,
interconnection issues that are coming up, and then,
we'll have a number of our audience members talking
about that. And we're gonna be able to do a nice,
robust question and answer period. Because this is the
time when we get to talk about the new renewable
natural gas projects that are coming to the state of
California. At the end , we'll do, if there are other
topics that we haven't touched yet, we have question
and answers then, and then we'll talk about next steps
and will close. And our list of presentations are
here. I have most of your slide decks. If you have any
last minute slidedecks, I look forward to receiving
your thumb drive in advance. And just before we get
started with the main event of today, our presentations,
Jamie Ormand: I would like to introduce our
very special and esteemed guest. Are you ready?
Commissioner Rechtschaffen. He is the lead Commissioner
on this proceeding. Rulemaking 1302008. He has
an illustrious career. He is here, one of our
Commissioners at the agency. And, Commissioner,
would you liketo go ahead? Would you like the
podium? Would you like to go from there? All right.
Commissioner Rechtschaffen: Thank you, Jamie. I came here to give a very
brief introduction. I didn't realize I was going to also get inspiration
from Jamie, but thank you very much for that. I did expect my picture up on
the on the screen, but I'm sorry about that. Thank you. For those of you
who came early and attended our meeting and sorry for the adjustment in
schedule, we, this is obviously critically
important that we address this order
that we did this morning dealing with an investigation into the public
safety power shut offs that have been occurring throughout the state over
the past several weeks. I want to thank all of you for your engagement in
this process. Overall, for coming to all the workshops. This is one of our
proceedings that requires a lot of effort,
technical expertise, staying with
things. And this group has done a very good job in doing that. I'm delighted
to learn from Jamie that she has a whole team of talented people. So
welcome to the rest of you. I really just want to extend my thanks to the
parties who worked very, very hard in coming up with this uniform pipeline
interconnection tariff, along with the uniform interconnection agreement,
that should really help facilitate
pipeline injection and make things easier
for all parties involved. Parties will no longer have to face different
requirements, different strategies, different issues in different parts of
the state. And that's extremely helpful. There's not, we can't we can't
change the world and eliminate all
obstacles. But this could be a very, very
important one. As many of you know, we're working to do other things to
facilitate bio-methane injection into the pipeline, the legislature extended
the deadline for dispersing pipeline interconnection incentives until 2026.
And we've issued a ruling that would establish a reservation system which
would allow developers to get, basically,
a spot in line until the project's
finished and incentives are available. And we're working very hard on
looking at hydrogen injection. What standards should be appropriate. And we
expect to issue a ruling in the near future. So thanks again for your work.
I apologize again for interfering with your lunch. Hopefully, Jamie will
not crack the whip too hard and she'll give you a break or two. And I look
forward to hearing about a productive session today. Thanks very much.
Jamie Ormand: Thank you, Commissioner. All right, so let's dive
right in. I'm gonna call up our joint utility presenters. I'm gonna
pull up your slide deck, and I'm gonna let you get to it. Also,
just so you know, on the back table, we have the agenda for the
day, including the presentations and the draft standard tariff, so
you can have the document in front of you as we're going through
different sections so you can look at the text and determine if it
meets your standards. If you have specific thoughts and comments,
we're gonna let the utilities do their presentation, and then we're
going to have a robust question and answer period so that all of
your questions can be answered in preparation for comments, which
are due on the 21st, and reply comments, which are due on the 31st,
which will help to shape this preliminary draft of a living document
that will help create this platform to interconnect new renewable
natural gas projects to the grid and decarbonize the system.
Come on down, joint utilities, whenever you're ready. All right.
Jamie Ormand: There we go. But it's not
showing on the screen. All right, Thanks,
Robert. As we're managing our technical issues,
why don't you guys introduce yourselves.
Jamie Randolph: Okay. Hello. I'm Jamie Randolph.
I'm with Pacific Gas and Electric Company.
Unknown: Push the green button.
Jerry McPherson: Jerry McPherson. SoCal Gas.
Ivan Salada: Ivan Salada, SoCal Gas.
Dana Walsh: Dana Walsh, Southwest Gas Corporation.
Brian Thatcher: Brian Thatcher, Southwest Gas Corporation.
Jamie Ormand: All right, so I'm gonna go ahead and just get started while
she's working on this. We got it. So, we represent the utilities that have
been working on drafting the proposed rule that was filed on November 1st
for renewable gas interconnections into the utility pipelines. Can go ahead
and actually go on to slide three, our introduction. Oh, I have it. I forgot.
Thank you. All right, So that that was supposed to be our introduction
slide. So the utilities started working on this, really, back in July of
2018, there was a ruling that came out that, in this proceeding, that asked
us to start working on a draft tarrif rule for an interconnection process
for renewable gas. October 2018, we filed a very high level outline of what
our processes looked like and where they were the same and where they were
different for the most part. And we came back and we had a workshop on what
we filed back in May, and got together and it was decided that we should put
together more robust rule that could be submitted as a proposal for getting
a renewable gas interconnected into the pipeline system that could be more
seamless across California. So the utilities got together. We wanted,
Jamie Ormand: We want to encourage renewable
natural gas, renewable gas, not natural
gas, but renewable gas to be injected into our
pipelines. We want to support California's
carbon reduction and greenhouse gas emission
goals. And so we got together, and we put
together a pretty robust project plan and
process to draft this rule that we submitted on
November 1st. We've got about probably about
40 different resources from the utilities
that have worked together on this since the
beginning, or the end of June, beginning of
July, we've been meeting about twice a week,
some weeks more. There's been a couple of
weeks where we only met once a week, but I'd
say we've been consistently meeting and every
meeting has at least 10 to 15 people on. And
then we're kind of talking amongst the resources
and then coming back together. So we went
through a process of outlining the tariff,
and then we walked through the different
sections that we thought would make sense. We
looked at our existing rules for interconnection
and pulled out what information made sense
from those. And so these belong here and then
looked at the different differences between
the different utilities in the processes and
what's in the existing rules and try to
figure out what was the best practice or the
best of all the worlds that we could put
together for us to come together on this. So I
think that's probably enough on the process.
Jamie Ormand: So this rule, who does it apply to? This is for anyone who is
going to be injecting renewable gas into a utility pipeline. It's not, it's
not for the fossil gas. This is
specifically for renewable gas to give them
guidance and direction on how to do that. The rule, if you haven't looked
at it, this is kind of a very high level organization of what we put together.
We have a table of contents, we have definitions, the definitions are
in there so that we could align on our definitions, applicability and open
access. Then we have the process, the interconnection process. We have what
the costs are. We have a section in there for local government entities
that are renewable gas interconnectors. We have the specifications in gas
quality, information in there that some of it is in existing rules. But this
is what specific to our renewable gas. Then we have something that came out,
we had a proposal that we were, that we filed in June on pipeline blending
exception process, and that's in this rule. And then we added some sections
on discontinuance and termination and dispute resolution. That's a very high
level overview of what's in the rule. So I think this goes down to Brian.
Dana Walsh: Okay, so, we wanted to
highlight a few of the rule sections that are
new to this Joint Utilities tariff. And one
of those sections is the Section J local
government entity section. So this section
realizes that utilities, on a case by case
basis, can negotiate with local government
entities, basically cities or counties,
as defined in the California Constitution. And
this just recognizes that they are unique
entities. So there's unique property ownership
characteristics. There's creditworthiness
that they may not need to post bonds
performance insuranceand that recognition of
a different payment cycle based on the meeting schedule of a government agency.
Brian Thatcher: So another section that was
added is the pipeline blending exception
study. Which is Section L. The reason why
this was included was to kind of expand
the opportunities for people to, you know,
sell renewable gas to the utilities.
Even though the based gas quality issues
may not meet the standard, but after it's
blended in, mixed in with the gas already
in the pipeline, the quality of the gas
may be acceptable. So we feel this will
allow some additional interconnectors to be
able to move forward with selling gas to
the utilities. When we do the study, we'll
evaluate the quality gas it'll have downstream
after the pipe or after the gas has
been blended in with the gas in the
pipeline. If that gas is considered to be
interchangeable with other gases that we use
historically, contractually, then we can
accept that blending study. We want to
point out that the interconnector will be
responsible to pay the cost of the study,
and the interconnector will need to make a
request for us to perform the study. And
then we also reserve the right, if we accept
the blending, that sometimes the future, when conditions change, we may have to
rescind that option. For instance, we may
have a major customer that terminates service
with us, and therefore we no longer have enough gas low to safely blend the gas.
Dana Walsh: And so, in that instance, Section M
talks about discontinuance and termination and that,
those, that scenario will be governed by the agreement
that is entered into between the utility and the
interconnector. And then, if there are any disputes
regarding the utilities' performance under this tariff,
there's some dispute resolutions. That starts with
giving the other party a notice that there's a dispute.
And then we recognize the Commission's alternative
dispute resolution process that's already in the
regulations and, or if the parties agree, they can choose
a third-party mediator on go through the mediation
that way. But if the parties had already included a
dispute, a different separate dispute resolution process
in their interconnection agreement, then that process
will be used instead of what's in the tariff.
Brian Thatcher: Okay, so here we just want to point out
that in the rule we've defined renewable gas instead
of renewable methane, although most applications we expect
to be bio-methane. We define it as renewable gas in
an effort to allow different forms of viable renewable
forms of gas to be used in the process. So, basically, if
we just defined it as renewable methane, then it would
exclude other forms of renewable gas such as renewable
hydrogen, so we wanted to make sure it was more inclusive
in those respects. This here is how it is actually
defined. Gas from biogenic or other renewable sources,
such as bio-gas, biomass or power to gas from renewable
electricity that has been conditioned or upgraded to comply
with this rule's gas quality specifications, including
biomethane. So that is the definition we came up with,
again, to be more inclusive of other forms of gases.
Brian Thatcher: Now, I'll talk about the interconnection
process. The very first step is for a request
to be made by the potential interconnector. This
needs to be done in writing. The utility will have a
fact sheet that will need to be filled out. You'll
need to put in there the volumes you can deliver,
what type of gas quality standards you have, any
seasonal flow rates and things. It'll be, you know, the
information will be on the fact sheet, and you'll be
able to follow that. The first step the utilities
will do, we'll perform an interconnection screening
study. This is kind of just a feasibility check. We'll
determine like what is the nearest pipeline that has
sufficient takeaway capacity to move the gas? And any
type of pipeline requirements that would be necessary
to get from the interconnector's site to where the
pipeline is. And the pressure requirements would go
along with that as well. Next step, after that, would
be a preliminary engineering study. If the interconnector
is interested in moving forward. The preliminary
engineering study, then, we can get into a little bit
more detail, more specifics on the exact location
where the receipt point would occur. We'll do a site
visit to develop a cost estimate, at this point in
time, a very preliminary design and cost estimate
would go along with that. The type of facilities that
would need be installed, how much that would cost, look
into any type of special conditions that may impact
the cost. You know, the costs would include design work,
environmental studies, the cost of the installation,
and it's kind of a plus 100% minus 50% range on
the accuracy of the cost estimate at this stage.
Brian Thatcher: The next stage after that, after the interconnector, if
you get cost estimate, and you're still interested and you want to move
forward, then, the detail engineering study, at this point time, after
that is requested, then utilities can actually put a design together and
give a more in depth, more accurate cost estimate. That'd be more plus
50% minus 30%. Get into the, you know, the actual details of the design.
So when we get to the detailed engineering studies, I see it, you know
most, for the most part, we're moving forward with the project. We're
actually spend the money, collecting. The money is collected up front.
I should have mentioned, with the preliminary engineering study, the
interconnector's responsible to pay for that. There's a True Up at the end.
If that, you know, the estimate is not exact on how much that'll cost.
And same thing with the detailed
engineering study. You know, there's money
up front that the interconnector has to pay, to pay for the procurement
of materials, design costs, engineering costs, other studies and costs
like that. When we're done with the engineering study, then pretty
much everything is ready to go, to move forward with construction, which
is the next step, would be to move forward with construction. The
rule has the options in there for either the utility to install the receipt
point, any pipelines, etcetera, or for the interconnector to do it
themselves. Of course, if the
interconnecter wants to it themselves, then
there are certain standards you need to follow, you need to obviously
work with the utility closely. They'll review the design, have to accept
the design. The materials will have to be from approved vendors, that sort
of thing. But ultimately, the utility has to take ownership of these
facilities. So you know, we need to make sure we're comfortable with what
is installed by the interconnector. If they choose that option. And then
last of all is the interconnector may withdraw the request at any time,
along the process, anywhere along here, before actually flowing gas, you
can withdraw. At the point of withdrawl, then any money that has been
given to the utility that has not been spent would be returned to the
interconnector, that type of thing. So that's basically the process.
Jerry McPherson: First, I should mention that I'm also representing
San Diego Gas and Electric as well as SoCal Gas. I forgot to
mention that on the introductions, as well as Ivan. Section I of
the interconnection rule addresses cost and the incentive programs
that are available to help encourage renewable gas interconnections.
But as Brian mentioned, the interconnector is responsible for
the installation costs, any expansions, repairs, upgrades or
modifications that are necessary to accommodate their gas initially and
throughout the term of the agreement, they're responsible for the
operation and maintenance cost, but the utility incurs to maintain
interconnector access. Currently, there are two unique O&M, operation
and maintenance, cost recovery mechanisms. PG&E recovers there
cost in their backbone shipper rates, SoCal Gas and San Diego recover
their costs directly from each interconnector, pursuant to a
schedule is called CPS, California Producer Service, and I think
Southwest Gas is developing their O&M cost recovery mechanisms.
Jerry McPherson: The existing incentive programs, that the
Commissioner mentioned at the beginning that have been extended for five
years, are in this rule, and you know, will be removed from the
existing utility rules. The addition that we've proposed, as part of
this interconnection rule, is that the incentive be made available
to third party pipelines. We think that provides an opportunity to
maximize the existing infrastructure and to more cost, effectively
increase utility receipts of bio-gas, bio-methane and renewable gas.
Ivan Salada: On the gas quality side. After our
discussions and conclusions we made since the
last update, we decided to keep our Unique Place
Utility Gas Specifications and, the system, due to
the following reasons, our system and customers
equipment are set differently. We have a different
historical gas, different air district limits,
and also sulfur or odor limits are different, as
well as our appliance and set up. We also do not
want to limit the producers, the local producers
in California, and ask these different specifications
will require them to make changes to their
processes. We also updated some of the renewable
gas constituents, and we added on carbon monoxide
as, considered of concern. And we added the carbon
monoxide trigger level at 0.3%. So it is a limit
to protect for strength, stress crack corrosion.
Finally, we have our Renewable Gas Source
Certification for siloxanes and testing and, in it
our utilities may do additional siloxane testing at
their own discretion and cost. So that's one of
the things that we have in there, also siloxane
results lower action levels. Um, I'm sorry, any
siloxane results above lower, above the lower action
level will not result in reduced siloxane tests.
Yes, and the Integrity Protective Constituents are
tested quarterly if above the trigger level and
reduced to annually when there are four consecutive
tests below the trigger level. We also added the
that if Integrity Protected Constituent results
are above the Lower Action Level three times in
12 months, then the producer will be shut-in.
Jerry McPherson: This is a little preview of the work that's been ongoing
to develop a joint interconnection agreement. We've been, in parallel
with the development of this interconnection rule, we've been working
on developing a joint interconnection agreement. Some of the challenges
are gas quality differences, that Ivan discussed, different regulatory
backgrounds, as an example, PG&E has a background system that was created
through separate and unique regulatory process that governs cost and
allocations. SoCal Gas in San Diego have a separate regulatory history
that established our backbone
transportation system. We all had different
forms and processes for doing the capacity studies of preliminary and
detailed engineering studies, and the interconnection agreements themselves.
We had different processes in terms of the interconnector self-build.
Some utilities allow engineering procurement in construction and others
just a procurement and construction. So the approval of the extension
is really going to give us the time that we need to work through all
those differences and come up with a joint interconnection agreement.
Jerry McPherson: I'm not done yet. So, as part of the
interconnection rule and the interconnection agreement, we
envisioned that there will need to be some changes to the
other existing rules. First and foremost, the existing
bio-methane provisions and some of the other rules would
be removed and consolidated into this interconnection
rule and agreement. Their updates to each utilities
definitions. As an example, SoCal Gas in San Diego have a Rule
One California producer definition that needs to be expanded
to include renewable gas. It's that California producer
definition that gives interconnectors a set aside
preference, and the SoCal Gas in San Diego Triannual Open
Season Process where takeaway capacity rights are secured.
And as we work through the interconnection rule, we may
discover that there are other changes that may need to be
made as we come to a common interconnection agreement.
Jamie Randolph: That's our presentation,
so we can take questions now.
Jamie Ormand: All right, thank you very
much. That was a lot of information again,
I encourage, if you don't have the
document, the draft tariff in front of you
and the language in front of you, there are copies on the back table, so that,
as we're going through questions and
answers, you're gonna be able to reference
the part in the tariff where we're talking
about. Because it is the language itself
of the tariff that we are going to be discussing right now. This part of the
workshop is the robust conversation about
the tariff. And if you have questions
about how it would apply to your project's
interconnection process, should this
tariff get adopted, now is the time to come to the microphones and bring your
questions to the front. We have the experts
who know the answers in the room, and
we should not miss this opportunity to ask
them why they did what they did. So in
this presentation, we have gone through all the different parts of the tariff,
including the gas quality standards, costs, interconnection process, who can
construct, how to apply, how to withdraw.
I am sure you have huge numbers of
questions, and this is the time that we're
going to set aside to talk about it. So
who is the first industrious individual who has a question? Thank you very much.
Jared Smenk: Is this working? Oh, very good. Hi. My
name is Jared Smenk. I'm with San Joaquin Renewables.
We're a project development company developing a
renewable natural gas project, but based on the use of
biomass via thermal gasification. So first question
is does the new rule here allow and accept the use of
thermal gasification as a conversion process or production
of renewable gas for injection into the pipeline?
Jerry McPherson: i'll let Ivan speak to the specifics of the
gas quality provisions, but it was our intent to open up,
even more so than the existing rules, thermal gasification and
other forms of gasification of organic waste that would meet
the renewable gas definition. So, that's why we propose the
carbon monoxide limit. And we requested that, in our pleading,
that carbon weha established some figure limits for other
constituents. So that's certainly our intent and our hope.
Jared Smenk: That sounds very encouraging.
A follow up question, if I may. Are there
any additional California rules, definitions,
potential, for example, in the health
and safety code, pertaining to definitions of
bio-methane or bio-gas, that might somehow
come into conflict or be problematic with
the rule that you are proposing here?
Jerry McPherson: We've had some discussions about the
health and safety codes. I can't give you a definitive answer
on that issue, but it's something we're gonna have to work
through. I don't, anyone else has any comments on that?
Jamie Randolph: Yeah, I would say those codes don't impact
your ability to interconnect into the utility pipeline with this
rule. They may impact you in other ways, but we will, we can
accept the gas as long as it meets the specifications that are in
the proposed rule. The Health and Safety codes have some stuff
about what's considered, what could be considered for different
incentives and things like that, but it's not a barrier for
actually interconnecting and accepting the gas into the pipeline.
Jared Smenk: Okay. Is the extent of the
impacts related to the incentive programs, or
are there other potential impacts of health
and safety code definitions beyond that?
Dana Walsh: I'm not aware of any other impacts
Jared Smenk: Okay, okay, very good. Thank you.
Jamie Ormand: I have a follow up question. Can you talk about the
process that you went through to come up with the additional rules for
gasification and why all the utilities determined to put this, that
additional carbon monoxide standard in this tariff, please. And go deep.
Ivan Salada: Yes, within the gas company, we
have previous studies that were done on carbon
monoxide for gasification. So within the gas
company, we had previous studies on gasification,
and they identify carbon outside of one of those
components that could cause stress, cracks,
corrosion and therefore the limit of points .03%.
is just to prevent that stress crack corrosion.
Jamie Ormand: Would you say that that new addition of carbon monoxide
specifications in any way limits new projects from interconnecting
to the pipeline? Or is more of a formal guidance about how the
interconnection process would work for projects that use gasification?
Ivan Salada: I'm not aware of the normal or the average concentrations
of carbon monoxide that may be present in new gasification
projects, but definitely those limits are set to protect our pipelines.
And there may be different limits set by Health and Safety code.
Jamie Ormand: Can you talk about how, oh, go ahead.
Jerry McPherson: Jared can correct me if I'm wrong, but my understanding
is that carbon monoxide limit is not going to be a problem.
Unknown: Okay, This is still on. I just want to
share with everybody, this is detachable. So if
you like to just raise your hand, I could bring the
mic to you. But I do have one question. At 0.3%
is when you measure it for stress cracks. At
what percentage of carbon monoxide does it start
presenting stress in the infrastructure? At 0.3%?
0.2%? When does it become dangerous to the public?
Ivan Salada: So based on the information
that we have, 0.03% is the level at which
it will represent a risk to our pipeline.
Below those levels, it would be okay.
Jared Smenk: Yeah, Jerry, just to answer your question. It isn't possible
for CO to be present, but as long as we know what the maximum when it is or
trigger levels are we can absolutely adjust the gas to meet the pipeline
specifications. So that's a very achievable
objective for us in our project.
Jamie Ormand: Come on down.
Tom Henz: It's better than the stands. I can look at their eyes. Dr Tom Henze,
Seal Team Bio Gas. I just want to applaud
the effort that you guys have done,
having many of the pioneering scars of the initial interconnection challenges.
It's come a long way, and I want to thank
you the IOUs for that, and especially
applaud the Commission, but I have a few questions. I want to make sure and clear
up, first of all, I'd like the Commission,
and I don't know if this is the
proper forum, to consider increasing and expanding the incentive tariff program
and make it $400 million. Then, also carefully reconsider looking at the
reservation system and just make the fund
large enough, whether it's business or
government managing for results. We want more bio-methane in the system. That's
going to impact greenhouse gases today a lot faster if we do that. So if the
fund is all about getting interconnected and it's large enough, you don't need a
reservation system that could be gamed. Let's face it, that's happened with
electric in the past. So that's just one
comment, but I do like the idea of having
an opportunity that the projects are gonna have some known funding. I'd also
like to have the Commission to carefully consider increasing the funding on the
incentives from 50 to 100% for many of the
project's because, first of all, there
are many dairies out there that have the opportunity to interconnect and those
are clearly identified in the IOU infrastructure. However, in the state of
California, there hundreds of miles of
mid-market player pipelines, third parties,
and I want to applaud the Commission and all the IOUs and changing language in
Section, I believe It's H, it's on page
19H, and then section D III, successfully
interconnect the utility or third party California pipeline system. Leveraging
installed infrastructure in the state of California can make a huge difference
for projects to happen today. All the
existing third party interconnections already
have a capacity allocation and are ready to take gas. They were taking the gas
in through the existing gas infrastructure
in the state and in state production.
The reach of these third parties could dramatically increase the eligibility
of dairies that weren't ever even likely or possible to do gas injection or
maybe even possibly electric because of the ability to uptake either the energy
or the fuel. I would like the Commission to applaud that change that third
party interconnects, and they are already
meeting or will meet, specifically,
the gas quality standard by having the revised
COPAC, the agreements to interconnect
and the gas quality standards,
specifically the PG&E interconnect in the
state. So there is this infrastructure out there, and that needs to be looked
at very carefully because we're not really
being as ambitious as we could. The
dairies are out there. The biomass is out
there. The previous speaker had mentioned
taking in the taken it from bio-gas, changing the definition, or better yet,
clarifying it to biomass and biogenic resources. Biomass has to go somewhere.
We've been facing an all-electric mantra from some of the opponents to all this
legislation, and the truth is, the organics
are gonna be here as long as people
eat, drink and defecate in California. We've got a biomass problem. So if the
all-electrical people want to not eat
food grown in California, not defecate in
California, they're welcome to live in
California. The air quality will improve,
and alls I want to see is common sense prevail. Manage for results. Create a
big fund, not a reservation system. Break the tape, flow the gas. Get paid.
That's what you would do with an employee.
That's what you do with your government.
You're aligning this ?????? with greenhouse gas reduction. You want more
projects? Make a big enough fund. The reservation system is just gonna end up
being another instance where it's gonna be gamed, and again, more access to the
third party pipelines with the streamlined
rules is fantastic. The utilities have
done a great job. You've gone from
multiple years to interconnect to several
years. But let's be honest. The third party
is already out there. They were gathering
the gas through the state. Let's leverage
that. We're all on the same team.
Utilities aren't there, the utilities are
aligned, the state policy is aligned.
Now we can achieve rateholder, stakeholder
and citizen benefits that can't
be accrued. Essentially, what we're doing
is we're finding a better pathway to
return money to the dairies, to the Ag
community, to internalize the externalities
of production of these materials, of their
products. You can't do it in a commodity
driven market. I'm sorry for getting into the economic argument, but the
all-electric has said there's no guarantee
any of these tariffs or any of these
things are gonna increase demand. The truth is, is if you create a demand, you
will create a supply. It's basic economics.
All these other arguments against
the opponents, they're just economically unsound. That's my comment. Thank you.
Jamie Ormand: Thanks, Tom. Let me just say that I encourage you to please
submit your comments in writing to the proceeding so that they could
be taken into consideration by the
Commission. As we know here in a workshop,
we're here to discuss the interconnection
tariff and ask questions
about why we did certain things in certain ways. And then throughout
the day, I'm going to continue to request that you take your comments,
write them down and submit them into the procedding as comments and reply
comments on the docket for consideration. Thank you. Next question.
Ken Brennen: Ken Brennen, speaking for PG&E, not the
joint utilities. I'd like to support what Tom Henz just
said. Utility pipelines are built to serve demand, and
our pipelines are not located in the outlying areas
where a lot of these dairy projects and landfills and
some wastewater plants may be located. Third party
pipes have a reach that PG&E's pipes do not. Back in
2017 and '18, we developed our interconnect agreement
with this in mind for a third party interconnect. The
goals of AB1900 and this rulemaking were put forth prior
to the contract being developed. So this is a new
concept, and it would really facilitate these projects,
I think dramatically, if we could have that third
party incentive actually become a reality. Because we
just don't have pipes everywhere. And third parties
are places where we are not. So it's a good benefit.
Jamie Ormand: Thank you, Ken. I encourage you to put your
comments in writing and submit them to the Commission so
that they could be considered in the proceeding. Utilities,
can I ask, while we're on the topic, obviously, Ken just
discussed why PG&E thought it was a good idea to extend the
incentive dollars to third party pipelines. Can the other
utilities chime in as to why you agreed so that we could make
this part of the statewide tariff that you proposed? Please.
Jerry McPherson: The same statewide goals that we all have
to increase the amount of renewable gas in our system, to
help us meet our greenhouse gas goals. We probably don't have
that third party pipeline infrastructure that PG&E does.
But there is some. There are some merchants, conventional
fossil fuel gas plants, that have their own gathering systems.
And that may create the opportunity for some additional
bio-gas in our system that we would not otherwise realize.
Dana Walsh: Thank you. I think for
Southwest Gas, we can echo what was already
been said and realize that, we're a smaller
player in the state, but we you know,
whatever works, whatever is working for PG&E right now, you know, we're not, we
don't want to stand in the way. We really
support this renewable gas effort.
Jamie Ormand: Thank you. Right. More questions. Come on down.
Darryl Moss: Good afternoon. My name is Darryl Moss from Moss
Energy Works, we are a dairy bio-methane developer. Have one
facility currently injecting dairy bio-gas into the SoCalpipe
and other ones on the way, so we appreciate all your support in
getting that done. I have two questions, I think, for starters,
at least, in the narrative at the beginning of the draft
statewide tariff, it says that the utility will engineer the design
for the bio-methane interconnection, and then a little later
on, and I could get the reference, if you need it, I grabbed
it on my phone here, it says that the utility will design and
engineer or provide specifications, inspection, and oversight,
if applicable. And my question is, what is your interpretation
of the way the tariff is currently designed, regarding the
ability of interconnector to do its own design and engineering
under the supervision of the utility? Is that something that
is at the discretion of the interconnector or not? As written.
Jamie Ormand: Point of clarification. Are
you talking about the rules as they exist
today, or the rules as we imagine them should
this tariff get adopted by the Commission?
Darryl Moss: As we imagine them. This is on
section F2C of the proposed tariff you circulated.
Jamie Ormand: thank you
Darryl Moss: and I should clarify that the current rule, as we
understand, it is that the interconnector always has the right to
choose to design and build their own facility under utility
supervision. And so I'm wondering what the intention is with this rule.
Jamie Randolph: So, currently, PG&E does not have the option for the
interconnector to design. Only to construct an install. So PG&E is
trying to work towards aligning with the other utilities on this, but
we're hoping to get there so that we can all be on the same page.
We're working on that internally right now, but the other utilities
do have that option as far, as I'm aware, to do the whole thing, the
design, construction, and install by the interconnector within the
provisions and set forth by the utility. That answer the question?
Darryl Moss: I think so. So do you believe the language as written reflects
that? Is that the intention of the language that your group has drafted?
Because it's a little bit vague? It's not, it says as applicable. It's
not quite clear how that is intended to be meant in the draft language.
Jamie Randolph: Yes, so it's already approved and applicable for the other
utilities, but not for PG&E. So we wanted
to, we didn't want to take away any options
that were already available. But we're still working through, it takes a lot of
process and people to make sure that you
have it put together correctly, and we don't
want a to misstep in that process, since we
don't have it in place right now. And so
we're making sure that PG&E get everything
ready to go so that we can do it safely
and make sure things are done within the right standards and that everything's
done properly and we couldn't do it as
quickly as we were drafting this proposal.
Darryl Moss: Okay, that makes sense. So the as
applicable means as applicable to the existing utilities
tariffs. I had one more and this is more for SoCal. The
narrative incorporates by reference the Interconnect
Collectible System Upgrade agreement, which is the
agreement, once you begin procuring equipment that the
interconnector executes with SoCal to begin purchasing
equipment. That agreement currently has warranty
language, which was really difficulty, I'll talk about
a little bit later, requires warranties that are not
currently offered by the industry, and the question
is, is that an agreement that since it's incorporated
by reference, it would tie this new statewide tariff
to that agreement? Is that an agreement that there's
also an effort underway to modify? Because the last time
around, we had to get a, you know, an advice letter.
Jerry McPherson: Yes. So one modification
specifically to the warranty agreement
that were all gonna be collectively working through, but what SoCal Gas
in San Diego are envisioning is that you attain warranties equivalent to what
the utility would have received had they procured the materials themselves.
Darryl Moss: Excellent. Thank you.
Jamie Ormand: Next. Sandy.
Sandy Goldberg: Hi. I'm Sandy Goldberg.
I'm too short, and I'm an adviser
for Commissioner Rechtschaffen. And, just a couple observations maybe.
Sandy Goldberg: I think it might be helpful to see some due dates, maybe for
the screening report to be provided to the applicant and the other reports.
Sandy Goldberg: Okay. Thanks. Also, I thought it was confusing where you have
to document that you did not get any gas from a hazardous waste facility. I mean,
generally, the gas is gonna come from the
site where the interconnection is, but
maybe not always. Anyway, I thought there,
it's unclear what documentation would
actually suffice for that. Could this be clarified? Could the, just sign an
attestation or what was what was meant by
that? And then I just wondered whether the
provision in K1, that the renewable gas specifications in Rule 30 and Rule 21
apply, whether that is currentlyrequired
for a bio-methane project interconnection.
Sandy Goldberg: You're shaking your head yes? Yes. Okay. Thank you.
Jamie Ormand: Also, Sandy, the hazardous waste
facility requirement that is in our existing
rules. Right now. So that's something that
we brought in from the other existing rules.
Sandy Goldberg: Okay. Do you have any
experience yet with how that is satisfied?
Jerry McPherson: We don't have any experience so far, but I
think we're envisioning a standardized attestation, as you
mentioned, where the interconnector certifies, you know, that
their bio-gas doesn't come from any hazardous waste landfills.
Sandy Goldberg: Great. So, actually, maybe that could be
put right in here. Or in the interconnection agreement.
Jamie Randolph: Next? Come on down.
Sean Edmond: Sean Edmond of Orstead Power.
Just a question, that looking at your page 22 on
your table. Can you speak to the renewable
standards as it would apply to hydrogen injection?
Jerry McPherson: First, can we make sure that we're,
is this table to page 22 that you're referencing
Sean Edmond: Page 22.
Jerry McPherson: Table two.
Sean Edmond: Second page. Starts on page, I guess it's
table one. Starts on page 21. Continues on to page 22.
Ivan Salada: Yes. At this point, the only limit that we have on
hydrogen is 0.1 percent and we're still trying to determine what will
be the lower action level and the upper action level for hydrogen.
That is still being research. And we have included other research.
Sean Edmond: Any kind of time frame on when you guys
were starting to make some conclusions around that?
Ivan Salada: We're expecting to have that information soon, but maybe
next year, maybe next year. I'm not sure about the endpoint for that.
Jamie Ormand: So Commissioner Rechtschaffen,
in his opening statement today at
the workshop, did mention that there is
documentation coming out of the Commission
at some point, hopefully soon, about
creating hydrogen injection standards. And
when that happens, we encourage you to
participate in that phase of the proceeding.
Sean Edmond: Thank you.
Jamie Ormand: There's more questions. I totally believe that you are all
thinking, how did the utilities put together
an entire interconnection tariff that
would apply to all the natural gas
pipelines of the state of California? You
have a question? Well, I'll ask a
question. We talked about the application
process, how to apply to the utilities to request an interconnection. Are the
utilities intending to create a standard application template that's going to be
available on all of your websites? That's
gonna have all the same information
requested to be submitted via some either
central or utility specific portal?
Jamie Randolph: We've had conversations about doing that. We have
not had time to address that yet, trying to get through this and
working on the interconnection agreement. But we do want to work
together and have something that's more uniform for that intake process.
Jamie Ormand: You think that that's gonna be available for the Commission
to look at by the time the interconnection
agreements are available in May?
Jamie Randolph: I'm not sure yet
Jamie Ormand: I think that that would be a wonderful time to have this
interconnection application form available,
if you were gonna ask me. Come on down.
Vince Woratmaja: There we go. Vince Woratmaja with the Wydeman
Group on behalf of the California Hydrogen Business Council. I'm
gonna take it back to the hydrogen point for a second. A, we are so
glad to see all the positive steps being made board on renewable
gases, period, including the nuanced definition to ensure that renewable
hydrogen is a part of this. B, very excited to hear Commissioner
Rechtschaffen's opening comments about a renewable hydrogen injection
conversation moving forward. We ????? strongly support the
joint utility renewable gas connection tariff and really hope that
it moves along speedily and that we adhere to timely processes,
so that we can boost the renewable gas markets, including for
renewable hydrogen. At a more high level, when it comes to renewable
gas policy frameworks, generally, we would love to see the renewable
gas tariff be used as a critical element to support other renewable
gas proceedings that ought to be opened in accordance with
legislative direction, including Ben Waso's SB1440 from last year,
which should include renewable hydrogen, as well as Nancy Skinner's
SB1369, from two years ago, which should enable renewable hydrogen
for uses, energy storage and to meet SB100 golds. More broadly,
while millions in this state are suffering the challenges of PSPS
events, we also encourage that renewable gas tariffs be implemented
to decarbonize backup power generation, including through the use
of zero emission fuel cells, critical building energy sources that
don't depend on the power grid, like gas heating and cooking,
as well as microgrid applications. Along this lines, we hope that
the PUC will expedite the separate microgrid proceeding, I believe
it's SB1339, and include demonstration projects that feature
hydrogen solutions, such as hydrogen fuel cells and electoralizers
that will optimize renewable generation in microgrids using renewable
gases. We do have a question with respect to the definition of
associated with renewable gas. Will the definition of hydrogen,
renewable hydrogen, include hydrogen derived from biogenic sources?
Vince Woratmaja: Our thinking is that this could be a long lines
of the eligible renewable resources defined in a PU Code 399.12,
Little E, or from any other carbon, slash zero, carbon neutral
slash zero carbon sources that are approved by the Commission.
Ivan Salada: At this time, based on the definition that we have, a biogenic
source is not outside of what is available or possiblity for hydrogen.
Vince Woratmaja: so it is a possibility
Ivan Salada: It should be based on the way we handle it.
Vince Woratmaja: Great. And we will put stuff into writing, Jamie.
Jamie Ormand: Yeah, I was totally just to encourage
you to write your comments down, so thank you.
Vince Woratmaja: Thank you so much for your work,
Jamie Ormand: all right. Looking around for more
questions. Now's the time. The experts are in the room.
Bill Graham: Good afternoon. This is Bill Graham with DBL
Inc. We're a developer and a provider of interdigestive
systems, primarily dairies in the state and nationwide.
I had a question, there was a new provisions that I saw
about the blending, and it looks pretty general. What you
presented so far, at least, in my read on it. Can you
shed more light or really more more detail on just the
process itself? And then the timing and anticipated cost.
Jerry McPherson: That's a good question. I think we've talked
a little bit about timing. I think, we're thinking, it was the
either 30 days or 45 days. I'm not sure. But we have had some
discussions about how long it would take. Somewhere in that
time frame. You know the process will probably vary a little
bit by utility, utility by utility. I know at Southwest Gas,
you know, we're gonna look at, basically, we're trying to
determine what's the gas in the pipelines gonna look like after
this gas is mixed in and it's kind of one product not two. And,
you know, there's a lot to look at because, you know, we're
looking at maximum flow from the interconnector during times
of our minimum flow. The directionality of the flow is one
thing that coming into play. We may have a pipeline that sometimes
it's flowing north to south. Other times it's flowing south
to north, and there's a lot to take into play there. We're
also looking at, you know, how close is next customer and so.
Bill Graham: Maybe a function also of
what interconnectors proposing to put in?
Jerry McPherson: Yes, it's definitely, the
closer the, was proposed that we take, the closer
it is to the standard, more likely it is that
we can blend it in, effectively. Also, you
know, the more the demand on the pipeline,
that's, that may be the most critical thing.
There's a lot of, you know, a bigger pipeline,
lots of flow on it. Ability to blend something
in and everything to look fine downstream is
much higher than if you have a smaller pipeline
as well, so there's a lot of things that
we'll have to consider. And as yet, I don't
think any of us have, well, Southwest Gas
hasn't, so, haven't had to do one yet. So when
that first one comes along, I think, you know,
in a way, we gotta figure it out as we go.
Jamie Randolph: So in the actual rule that we propose, on
Page 29, the end of section L, we have 30 days for the pipeline
exception study, and that's within either the preliminary or
detailed engineering study. So it gives us the 30 days to do that.
Bill Graham: How about the cost? Any of you have cost?
Jamie Randolph: We don't know what the costs are
quite yet. I think it may vary for the different
utilities. And so we haven't got that yet since
this is new for everybody. We're still trying to
figure that out. We want to be able to encourage the
renewable gas into the system. So we didn't want
to, you know, we didn't want to shut down the idea.
We want to try to see what we can do, but we're
not sure it depends on each individual situation,
and some of them may be more complicated than
others, depending on the gas that's in the pipeline.
The gas that's being injected, the demand, all
these different factors, and they can all impact
the study too. Some of them may be pretty obvious
right up front and cost less. And some of them may
take a deeper level of analysis to figure out.
Bill Graham: A couple of questions on cost from sections 4A and
B, pages 16 and 17, from a finacability perspective. And a utitlity
could elect to upgrade systems at it's full discretion. An
interconnector would be obligated to pay for such expenses And this
question I would have is, are there boundaries set around where
those cost may occur? Are they downstream? Or are they just for the
project? Talk about the injection skid, for example, maybe laterals
into the pipeline. It seems rather broad, my first reading of it.
Jerry McPherson: Basic mandate is to recoup the costs we incur in
providing access, so most of the times, those would be at the point
of receipt. You know, a typical example might be, you know, an
instrument is no longer supported by the manufacturer, and you can no
longer get replacement parts or service, and you might have to replace
the total flow, for example. There's more and more electronics
at a point of receipts and the life cycle as you're probably well
aware is what, 3 to 7 years, before the manufacturing moves on to
the next version of his equipment. But most often is going to be
at the point of receipt. But it, costs can be incurred downstream,
ranging from BTU districts. The Lower BTU content that a renewable gas
interconnector would provide, depending on the volume that they're
delivering and how variable that is can dramatically impact the BTU
content that customers receive and therefore the infrastructure,
both hardware and software, that's needed to accurately bill customers
for the reduced BTU content. Those are a couple of examples.
Bill Graham: Another question I had is, on page 17, it says utility
abandonment shall be an interconnecter's sole expense. Is that at
the end of the project or anywhere along the way a utlity decides,
we're abandoning this, by the way, here's a check for, what is it?
Jerry McPherson: Termination conditions there clearly spelled
out and will be spelled up in the interconnection agreement.
But typically it's at the end of the life cycle or an unfortunate
circumstances. You know, when the interconnector goes into
bankruptcy or the project's not viable. That site needs to be,
um, restored to the original site conditions, usually pursuant
to the easement rights that are associated with it, which are
sometimes in the hands of the interconnector and sometimes not.
Bill Graham: The states of the utility, it
looks like it until the election til then,
Jerry McPherson: Again, those rights
will be spelled out, and there's, a utility
is not generally gonna have a right to abandon absent some of non performance
by the interconnector or some other extenuating circumstance that would make
it untenable for the utilities to continue
to operate that point of receipt.
Bill Graham: Might help, be more helpful
to have more language make that clear.
Jerry McPherson: I think the interconnection agreements
will do that, and the current versions of each
utilities' interconnection agreement really clearly spell
that out. I can't speak to PG&E's or Southwest Gas
agreement, but I know the SoCal Gas and San Diego
agreements, for example, typically have a 15-year primary
term and the utility has very few rights to terminate
after the interconnection agreement is up and operating.
Bill Graham: Thank you very much. Thank
you for the work to appreciate it.
Jared Smenk: Hi, Jared Smenk with San Joaquin Renewables,
again, my question is relevant to section K, the
renewable gas quality specifications, and specifically,
table one, where it speaks about the testing for
gas source. So are these gonna be applicable for, for
example, gasification projects, right? Nonhazardous
landfill, dairies and then other, I assumed gasification
and fall in that other category. Is that accurate?
Ivan Salada: Yes, that is correct.
Gasification will fall under the yellow column.
Jared Smenk: Okay. Can you speak to the
frequency of testing? Is this periodic
testing or is continuous testing required for these various components?
Ivan Salada: It depends on the levels found on the periodic testing.
So I could be quarterly. And, so it may be quarterly, may be extended to
semi-annual, to annual. It depends on what constituents are we testing? If
it's going to be for health constituents or pipleline ???? constituents
Jamie Randolph: All the testing requirements
are in section five. Of that section.
So you can read about that there. It's a couple of pages. A few pages worth.
Jared Smenk: Very good. Thank you.
Jamie Ormand: As I'm looking out into the audience for more
questions. Tom, you have a question this time? Yes, Excellent.
Tom Henz: Is there a question in that? That should be the
first question. Section C. Section I. Number five, and C,
under eligible interconnection. In the dairy pilot program,
they had a very helpful. In the Section three, they included
the cost of compression and the Cap X and Op X for compression.
Was that considered for also maybe extending into the
new tarrif? That would expand project opportunity, and if
there's a possibility to include making in the incentive
portion of the tarrif the eligibility for the same categories
for reimbursement for the developer, a little bit broader
category, it would enable some of the projects that are
smaller, smaller producers, to have an ability to put together
a cluster. So were those things considered that we could add
that to it? And the second part of the question is, if the
answer is yes, then there will be no follow up questions. But
if the answer is no, then I've got a follow up question.
Jerry McPherson: I can only answer yes to that. We
didn't propose any change to the existing legislative
incentive program. The only change we proposed to the
existing program was to extend that to third-party pipeline
interconnections. So under the existing tariffs that were
mandated by Commission decisions and directed by legislative
acts, dairy clusters have more costs that are eligible,
and they have a higher cap. Was that your question?
Tom Henz: Yes. Well, actually, a lot of the biomass
conversion facilities or the, and the gathering
systems, I would envision an opportunity where you could
take biomass, dairy bio mass, have a gathering line
system that takes bio methane or gas that is sufficiently
able to be upgraded safely and being injected at
an injection point safely. And that would, you know, a
dairy now is more or less located closer to nut or a
tree or some other biogenic source of materials. You
could envision more than one technology and more than
one development sharing a gathering line. And that is
really again, another leverage of the investment of
the state. And some of the smaller facilities could
access that with more ease, especially with compression
costs and things like that and so, if the answer is,
I know, it, maybe it wasn't, could it be considered?
And then alternatively, can the rules, I know this is
gas, but it is the CPUC, the, our brethren on the other
side of the table that produce fossil fuels, they're
allowed the energy production tariff, which under
PG&E is very valuable in the sense that it's a very
good price for the electricity for production. And
the other utilities have their tariffs. I know SDG&E,
possibly and SCE has, and Edison has their tarrifs
So make a energy production credit on equal footing for
the renewable fuels. That's something that probably
have to be added to a comment later. But it's a good
one because it puts the fossil fuel and renewable
fuels on equal footing. Let's subsidize what we want.
And that's what we need to do. We want to subsidize
renewable fuels. Okay, so we have to submit another
written comment to the Commission. Okay. Thank you.
Jamie Ormand: Did the utilties want to talk about your process
about considering out adding changes to cost allocation
to this tariff? And why or why not? Why you may or obviously
you did not decide to put them into this tariff here.
Jamie Ormand: More specifically, the question
is, Tom was asking, sort of about cost
allocation. We definitely have legislation
that has requested that the Commission
look into cost allocation for interconnection
issues. Is there a reason that you, in
developing this tariff, didn't just also
include cost allocation ideas in your filing?
Jamie Randolph: I don't have a good answer for that. Other than
we're on a time limit, trying to do we could in the time that we had
Jamie Ormand: Ah, the time limit answer. That's a fine answer.
Therefore, parties, if this is something that you want to bring up, I
encourage you to file comments with the Commission, with your ideas and
suggestions so that the Commission can take it into consideration.
Again, this is a living document, but the intention is that this would
be a living document that could be amended and updated in the future
as we continue to progress through renewable gas proceedings and
processes. All right. More questions. Rich. Do you have any questions?
Jamie Ormand: Okay. Come on. Ask your questions. Sure. You
definitely can add the comment. Please introduce yourself.
Carol Burke: My name's Carol Burke. I'm with PG&E doing gas
quality. And there are a couple of things that came up that
I wanted to talk about. One, there were questions about our
hydrogen limit. And, when we're developing these limits,
it was, the assumption, of course, is that this gas is gonna
be replacing gas that's already within our system. So, we
have to look at, you know, whether somebody could be receiving
gas that basically comes from Canada, one day, or this
other gas the next day. So our limits for hydrogen, you know,
not only do we have to look at something that's protective
of our system, but obviously, that your typical consumer can
actually accommodate this gas without having to make any
adjustments to their, any of their appliances. So that's one.
So looking at much greater allowance of hydrogen, like you
said, that has to be dealt with elsewhere because, you know,
I can't imagine us, you know, giving huge amounts to, of
hydrogen to people just are not prepared to take it. So that's
one. There was also a question about the costs associated
with taking gas. That might be, we have to blend. So I would
say basically, if we're taking gas that's not conforming
to our standards and we have to watch our system more carefully,
whatever that might mean, whether it means monitoring
additional, whether that means physical changes to our system,
those are the costs I think we're talking about having
to recoup. And then there was one more about the design of
our our own design of our interconnects. Because I believe
those interconnects, once they're built, then we take possession
of them. So, we want to make sure that, and of course,
at least with the first couple, we're going to make sure
those are designed according to our standards, though, that
whatever we're accepting is as if we did build it, design it
and build it our own. Anyway, that's my only finally comment.
Jamie Ormand: Thank you. Very helpful. All
right, I'm gonna ask for more questions
twice more, and then we're gonna have a, come to a vote and determine whether
or not I'm gonna give you a 20 minute stretch break now because we're ahead of
schedule, which is great. That means we are
presentations can have more time and more
questions. So this is the second last
call for questions because we have all of
our experts in the room and people who
actually worked on this tariff can answer
your questions live and in person, right now
to help inform the comments that you're
going to draft, write up and file with the Commission by the 21st of November.
Darryl Moss: Hi, at the risk of delaying our early
departure. I had a couple more follow ups. Maybe you could
help me just a little bit. As I understand it. So what
we're doing is we're building a statewide, Darryl
Moss again, Moss Energy Works. We have a statewide tariff,
but that tarrif is turning around and pointing to
the existing SoCal, PG&E, Southwest, other interconnection
tariffs, which so really, we have two tarrifs that
we will be under because, I guess, the follow-up
question, and I'll combine these, you can answer in any
way, is for example, PG&E has a $1 million assurance
deposit that we'd love to talk about that and have that
removed. But that's not even really part of this discussion,
because this tarrif is merely pointing at PG&E's
tariff, which would be modified via separate process.
Could maybe somebody help me out on how that all goes?
Jamie Randolph: What you were mentioning as
part of the interconnection agreements. It's
not actually in the rule that's existing. So
we are working on those common interconnection
agreements right now. We had started before
we filed this, but that's what we're gonna
be coming out with the beginning of May, so
we'll be addressing that in that process.
Darryl Moss: Thank you. This is a PUC 300 level college
course here, so I'm catching up. So is this statewide
tarrif then directing the construction of new interconnection
agreements as well? Or is that a separate process?
Jamie Randolph: I'm not sure what you mean by
directing, but yes, it gives you the process
and the guidance for how to interconnect
with a utility pipeline for renewable gas.
Darryl Moss: Okay, I think you've mentioned a
couple times that PG&E is working on revising,
harmonizing it's interconnection agreements. I
guess my question is, when it's doing that, is it
receiving guidance from this process, or is that
a totally separate process that will then take
public comment and generate and, you know, I'm
just trying to site. That question makes sense?
Jamie Randolph: yes. It's part of this process.
It's the next step in this process. So we
are, the interconnection agreement should align
with what's in this rule, and it will align
across the utilities, which right now they're
different. So you, when we submit that, that will
be open for comments. Just as this is right
now. Once that submitted. Is that the question?
Darryl Moss: I think so. So I think what you're saying is that the
individual utilities' interconnection agreements have to be consistent
with this tariff. But this tarrif is not directing utilities to do
anything in their interconnection agreements. Is that accurate?
Jamie Randolph: Yes. And no. We're gonna have
a joint interconnection agreement that was
the same for all of the utilities. Once we
come out with it. That will be aligned with
us. So it's not. We're not going to be using
the ones that are existing today for renewable
gas interconnections. There will be a new
one that we're going to draft and propose,
so, and it will be aligned with what is
proposed in this proposed rule. So if there's
comments or questions about the interconnection
agreements, or you want to get some thoughts
about those, you know, we welcome your ideas
as we're in the process of drafting those
right now, But you also have opportunity
after we file it to provide your comment.
Darryl Moss: Okay. Thank you.
Jamie Ormand: I can give a little more color to
that. Just so you know. This is a very big lift,
taking 4 utilities that have never worked together
to create something together. The first was aligning
the interconnection process piece. And then the
second piece, as our utilities have just described
aptly, is the agreement piece. And the reason that
we did it, that it was done in this fashion, was
because prior to their quest to make a harmonized
standard process, as you know, it was all different.
So this is a step by step movement into this standard
platform for renewable gas. And the utilities
just filed a request for an extension on the end of
October, the 22nd, I think, which is on the docket
card. And the Commission accepted that request for
an extension in a filing that was submitted to the
docket card on November 1st. That said, yes, we will
accept your May 1st filing. So I envision, although
I'm sure there will be more guidance on the formal
record, I envision that we will do something sort
of similar to this when the interconnection agreements
come out, which will be, there will be a filing.
There will be a workshop to have a conversation
about filing. Then there'll be an opportunity to
provide comments or replies on the docket, which
is this except for the next piece, so that you'll
have an opportunity to provide input. I'll echo what
Jamie said, which is, if you have forethought on
what you'd like to see, there is a opportunity to
provide comment here. And you might consider a section
in that comment because the utilities read everything.
We read it. They also read it. That helpful?
Darryl Moss: Yeah, that's very helpful. Thank
you. I understand it's a big lift, and I think
it's more, I'm not, please don't take it as
criticism. I'm just trying to understand the
process that someone who doesn't do this every
day, so it sounds like that's the direction
we're hoping the effort will go. And we appreciate
that's where that's where you're headed.
Jamie Ormand: Thank you. All right. Final final call. Questions.
Jamie Ormand: Come on. Oh, Yes. More questions. Questions are good.
Bill Graham: Bill Graham, DBL again, just to follow
on Darryl's question. So I think I have the answers.
Might ask it anyway. So there's an existing interconnect
agreement in place. Would this supplant it?
Jamie Randolph: Yes. So once we have the common interconnection
agreement, that will be the one that will be used for renewable gas
Bill Graham: Say there's already an a interconnect in place.
Jamie Randolph: If you already have one signed and
in place that will most likely be grandfathered.
(inaudible from off-mic)
Jamie Randolph: I don't know what that process is going to be for sure.
Jamie Randolph: Usually you have the option to be grandfathered in.
Bill Graham: Okay. Thank you.
Jamie Ormand: If you have thoughts about that, please don't hesitate
to provide them as comments to the proceeding. We will read them
Jamie Ormand: Are there any additional questions to the interconnection
process tariff draft before us? It's 135. So we are quite ahead of schedule,
which is amazing, because that means we're doing a good job. So I would like
to propose that we all come back and start immediately at two o'clock. That
would give you 25 minutes to either go grab a little food in our cafeteria.
Don't stray too far from the Commission. Anything can happen. But if I give
you 25 minutes, that's your stretch
break, coffee break, and then we're gonna
hit our presentations, and then we will get through them all, have all our
additional questions and answers, and then, let you out when that is done. Can
I get a raise of hands if we are okay with the two o'clock return? Starting
on the nose. Two o'clock? Okay. No objections. All right. I'll see you back
here at two o'clock on the dot. Thank you very much to our utilities. Thank
you very much to our commenters and
questioners. Please. Your comments are due
into the Commission on November 21st. Headings are great. Make them clear
and concise. Cite tariff language, cite tariff sections. We look forward
to receiving your comments, and we hope that this informed those comments.
Jamie Ormand: And pull it together for the next
part of our workshop in a calm, collected fashion.
We're gonna move into the interesting, another
interesting part of today's workshop. We're going to get
to discuss some really cool projects that are going
to be working to decarbonize our natural gas pipeline
system and all of the end uses in the state of
California. And as we're coming back together, just
to make sure, you know, we got everybody before we
start, I'll just give you a few thoughts on renewable
gas from the Commission. So one of the things that
I talk about a lot is that California is at the
very end of the line for our natural gas pipeline
system. We import 90 to 95, more like 95%, of the
natural gas, fossil natural gas, that we use in the
state of California every single day. On average,
5.6 billion cubic feet of fossil fuel natural gas
imported from out of state, which means we have a
large opportunity here in the state of California to
do something different. The role of the California
Public Utilities Commission is we make sure that
natural gas, renewable or otherwise, that gets into
the pipeline is safe and interchangeable with the
gas that's already there, so that the end uses, all
of them, aren't disrupted by the new source of gas.
Renewable natural gas can come from all sorts of pollution
sources. Pollution from our dairies, from our
landfills, from our waste water treatment facilities,
from our piles of agricultural wastes that aren't
consumed. I've learned about, I've learned from
some growers in Central Valley, that about 10% of
every crop cycle gets put into a pile to rot, and
all these varieties of waste methane gas, CH4, that
goes directly into the atmosphere as an atmospheric
warming pollutant, waste gas, could be captured,
cleaned up and shoved into our natural gas pipeline
system and used in all of the applications instead
of the fossil fuel natural gas that we import from
out of state. So the renewable natural gas docket
is a place where we get to talk about all this and
we get to think about how renewable natural gas from
all of its variety of sources can be cleaned up,
injected into the pipeline system, decarbonize our
natural gas pipeline system, and a lower carbon
intensity natural gas system is gonna help to
decarbonize the sector, which is totally in line with
SB100, which is the goal of a decarbonized energy
sector here in the state of California. Now that we're
back, I'll end my vamp and I'll just let you know
that, here on my left, we have just the next steps.
We were gonna do at the end. But I'm gonna put this
up at the end also. Right now, we have sort of two
formal dockets moving through the process, two formal
documents on the docket moving through the process.
So the draft renewable gas interconnection tariff,
which we have just talked about done Q & A, that
was filed on November 1st. Comments are due on
November 21st. Reply comments are due on the 31st. We
tried to give a good chunk of time between comments
and replies because this is a lot of information.
Also, there is a proposed decision on the reservation
system. Comments are also due on the 21st. Reply
comments or due, on that docket, on the 26th. I bet
you're gonna ask me, could we put them together?
Jamie Ormand: That's not what you're gonna ask me. Well, I'm gonna
answer the question that I just asked first. And then, then you can ask
questions. So you might be asking, can we put our comments together in one
filing? I'm not in charge, but if I were going to provide any guidance, I
would say, use the titling of your document wisely to enable the reader
of your document to know what's in it. Use headings wisely so that we
know what you're talking about. If you decide to combine. And if you don't
combine and you want to do separate filings, that's totally fine also.
Jamie Ormand: Okay, Jamie, you had a question.
You gotta come to the microphone though.
Jamie Randolph: November only has 30 days in it, so can we have till 12-3?
Jamie Ormand: Oh, probably. That's a good point. I didn't even
Jamie Randolph: and that's Thanksgiving week.
Jamie Ormand: So I guess it would be December
1st is not November 31st. So that'll get fixed.
Jamie Randolph: That's a Sunday.
Jamie Ormand: Then it's due on Monday.
Jamie Randolph: Okay. Monday after Thanksgiving?
Jamie Ormand: Yes. I guess that is. But you have until the end of the day.
(inaudible response from crowd)
Jamie Ormand: I would definitely say if you have a request
on a different filing date, the way that you make that request
is you email the judge and you CC the entire service list.
You don't make requests, requests, or ask questions without
CCing everybody in the service list. And you could find the
service list on the website, you can go to the CPUC Renewable
Natural Gas website. You can find the service list tab on
the right, or you go through the main CPUC website and
look under Proceedings, then you can go to the service list
button, and then you can control+F 1302008 to find our service
list. And then you could pick the comma delimited list for
all of the email addresses. If you have any questions about
that, my information is also on the CPUC Renewable Natural
Gas website. Be more than happy to guide you through the
process again. Okay. Thank you so much for pointing that out.
All right, so we're going to get into our presentations.
Jamie Ormand: Our first presenter today is Darryl Moss from Moss Energy.
I'm gonna put up your PowerPoint, and whenever you're ready, come on down.
Darryl Moss: Good afternoon, everyone. Great work, Jamie, keeping us moving
forward. This is inspiring to see the speed we're moving. My name's Darryl
Moss, I'm the CEO of Moss Energy Works. We're a company based out of Redding,
California. Together with our sister companies, we're about 50 employees that
do nothing but build, own, and operate manure digesters. So we're here today
to talk a little bit about our experience
getting dairy bio-methane into the
pipeline. While I wait for my slides will
tell you a little bit more about our
company. We were founded in 2010. We've been building digesters, starting in
Washington in 2007, about 25 completed,
mostly on the West Coast so far, and it's
been a great experience to get into
California. When we started in Washington,
it was kind of a slow, gradually developing industry. But the state of
California has provided very strong
incentives and very strong public guidance
that we want more of these digesters. So that is where our effort has been
focused and that's where we've grown,
working with a lot of folks in the various
utilities industries, regulatory
departments, that are trying to make these
projects a reality. Including Jaime, who's
trying to make our slides of reality.
(inaudible from audience)
Darryl Moss: Yeah, thanks. I don't know any jokes, you
know? So, I probably can just, I might just start on my
agenda, so we don't waste all your time. Are we waiting
for someone? For those of you who don't know, a dairy
digester is formed by creating an anaerobic environment on
manure. So dairy farmers are already pretty smart. They
use the manure from their cows as an irrigation and
fertilizer for their crops, so I don't have visual aids, but
if you can picture of a dairy farm works, the cows make
manure. That manure is stored in large ponds until the
growing season, the spring or the summer. Then that manure
is spread on the fields to make the crops grow. It's a
natural fertilizer, it has nitrogen and phosphorus and, of
course, water in it. And all those things make the crops
grow. The crops are harvested and fed back to the cows
to make milk and, of course, more manure, which makes
more crops, which makes more milk. So a dairy farm is
already a fairly well self-contained closed loop, to use
that physics term, and what we're doing in the digester
industry is we're capitalizing on that existing nutrient
handling system that happens at the dairy. The manure is
already being emitted. It's already being captured and
stored in a pond, and so in California, very good work.
The dairy digester technology we use is overwhelmingly a
covered lagoon digester, which you see in the picture
there, is essentially in very, in layman's terms, a big
tarp over a pond. There are other ways to build digesters.
We built them in colder climates out of concrete, out
of steel, different designs. But in this situation, this
is how it's done in California. So what, you see, there
is a fairly large California dairy with about 5000 cows
on it, and all of their manure going into the digester.
Darryl Moss: Now we'll move through my slides. I'm
gonna talk a little bit about digesters, some case
studies of our RNG injection, and then a bit of our
recommendations on the current PUC process. As I've
described before, this is a fairly small dairy, not
far from Sacramento, but it gives you a good visual.
Barns are built on a slope, the manure runs downhill.
You all know what runs downhill, and cow manure does
run downhill. It gets put in that big covered pond,
and in this case, you see, there's a small building
where that gas is burned as fuel to make a generator.
That particular facility supplies power to SMUD, to
Sacramento. But the industry is becoming more and more
focused on gas, and you see the crops all around the
farm. So that's a fairly standard, older, small
California dairy. When you put the manure from one cow
into a covered lagoon for two years, so that cow's
manure over the course of the year, will generate about
two barrels of oil worth of usable energy in the
form of natural gas. And we'll also remove about 4
to 5 tons of CO2 equivalent, which is more or less
the same as one car. So, in terms of achieving the
state's greenhouse gas goals, for every time you put
a dairy digest, a cow, and their manure into a dairy
digester, you're removing essentially one car from the
road for the purposes of greenhouse gas accounting.
This is a little time line of the California digester
industry. If you start at the bottom, in 2013, you
can see the history of projects being built in the
state. On the right side is our company, Moss Energy
Works. Some of those facilities we own, some of those
facilities the dairy farmer himself owns or herself.
Darryl Moss: And we operate on their behalf.
On the other side are other companies in the
industry. What you'll notice is two things.
First of all, the accelerating pace of digester
development as you get to the top of the
graph. Right now, we're bringing a new project
online about every 60 days. And then the other
thing you'll notice is the transition from
power projects, which are the little lightning
bolts, to gas pipeline projects, which are
the little pipe symbols. Over three-quarters
of what our company is currently doing is now
directed to natural gas. Power made a lot of
sense. There were long term contracts available,
but natural gas currently makes even more
sense. There's a lot of incentives and efforts
to try to get cow gas for use as a vehicle
fuel, not least among those the fact that then
you're offsetting conventional fuel, and that
is a goal the state has. The first facility
in the state, and so far the only one that's
injecting dairy bio-gas into the utility
pipeline, is located in Pixley, California.
That's Tulare County. It's actually within the
boundaries of an ethanol refinery called
Calgreen Ethanol, our company joint venture with
Calgreen to build this facility called Calgreen
Dairy Fuels. And so what we did is build a gas
cleanup and conditioning facility right there
in the ethanol plant. That made a lot of sense
because there was already a SoCal Gas pipeline
there, and there was already a large need
for natural gas in other places as well. We
did that by building a low pressure pipeline.
In fact, here's the map. That is, so far, how
big the project is. What we're doing is we're
building individual covered lagoon digesters
on individual dairies. So I showed you that
picture early on. I believe we have nine up and
running as of today. We have at least 18 are
gonna be online by the end of next year. And we
think this group will grow to over 20 digesters,
all of which produce their raw gas and then
deliver the gas through that low pressure
pipeline to the central cleanup facility. So
the red there is the completed pipeline. I
think we're up a little bit over 20 miles of
pipe all across Tulare County and the blue
is all the expansions being planned because we
found that once you have an RNG facility that
is successfully interconnected with the utility.
That's the hard part is getting that done.
Getting the sequence done, getting it financed,
getting through the bio-methane interconnection
process. Building the gas cleanup equipment.
Once you have that, the marginal effort
to add more dairy digesters is fairly modest,
particularly the covered lagoons which are
very cheap and easy to build pretty fast. And
so we are expanding this cluster very rapidly
while we're trying to also build new injection
points. But as I'm gonna describe, the
timeline for building new injection points is
really the key on how fast we can deploy more
dairy bio-gas. So this project, it'll be at
least four million gallons equivalent of CNG,
probably much more than that by the time we
expand it. Cost of something like that, about
51 million. You'll note that the digesters are
the most expensive part because this budget
is for 12 digesters, then you got a lot of
bio-gas cleanup. You have some pipeline costs.
The interconnection is actually the smallest
cost. The cost is still millions of dollars,
but the timeline is the key here. That is what
the interconnection impacts on our industry
are, the cost is less important than the time.
One of the ways we've been able to expand the
Calgreen Dairy Fuels project and we expect to
do others, is to, once you have a facility
where you can receive gas and get it into the
utility pipeline, is to truck gas from isolated
dairies that are too far away to pipe. And
so a few months ago, we brought online the
state's first virtual dairy bio gas pipeline,
where we're hauling compressed gas from an
isolated farm back into the central hub of this
cluster, and we expect to have four or five of
those running by the end of next year. It's
a little faster to develop. There are some
inefficiencies, of course, of hauling and
compressing gas, so it's not ideal. We would rather
connect everything by pipeline, but the technology
exists to haul that gas, trucks are all
powered by CNG, hauling CNG to put into the
pipeline, so it's a great option. It may even
be that we end up delivering more gas via truck
than by pipeline simply because you can build
it faster. Building pipelines in California
takes a long time. There's a sequence issues.
There's union issues. They're just things that
slow you down. It results in a good project,
but it's not fast. Next slide. Just to step
back a little bit. This map is showing all
the current dairy digester injection points
in the country that are injecting renewable
natural gas from dairy or swine. And as you can
see, there's five or six of them. Not that
many. And the blue, and I'm sure I'm missing
a lot. Blue and yellow are the planned and
imminent projects. As you can see, there's a ton
of them planned in the Central Valley, some
from my company, some from others. But you'll
notice that most of these are out of the state
and that is because of that time structure.
You might hear this theme, speed. It is much
faster to build a project in many other states
than here in California, but we do have
other advantages in the state that we're working
together to improve. Obviously, getting a
standardized tariff might be one of the things
that would help us speed up, so I'm glad we're
undertaking this. But all these projects, by
the way, shipped their gas to California.
That's where it goes. Finally, my thoughts and
recommendations on tariff and the preceding,
really, we have two of them. One of them was
mentioned a little earlier. It's not specific
to this proceeding, but one of the things that
California has done a very good job of is
incentivizing financial incentives to make
projects move away from doing nothing or move away
from generating power and instead try to produce
renewable natural gas which five years ago
was kind of a high risk, somewhat uncertain
endeavor for those of our industry, and now
it's become the main thing we want to do.
Part of that's because of the AB 2313 CPUC
reimbursement program, which is mentioned earlier.
That is a reimbursement of after you have
incurred your costs and gone online. A dairy
digester can apply for $3 million or a group of
Dairy Digest can apply for $5 million of their
costs. And that is the funds that we received
from SoCal for the Calgreen Dairy Fuels project
that we completed last year. It's based on
injection date, but there's a couple of problems
with that. It's a limited pool of funds,
which, of course, all funds are limited, but
it does limit how much projects can get in
there. And the proposed decision, which we will
be commenting on in writing, does set the bar
very low for a new program to reserve funds.
So I think an earlier gentleman discussed the
danger of gaming that system, which we agree.
If you make it too easy to reserve funds,
then the funds just all get tied up by whoever
is the fastest draw reserving them. And then
nothing happens. And that is something that
happens all the time in our industry is that
public funds are secured and held and go nowhere.
And so we will always be in favor and will
be submitting comments to try to make sure that
the program incentivizes projects, getting
online, getting built, getting gas in the line.
And that's what we're all looking for. The
second program, which is run here by Miss Ormand
is the pilot project, well her and others
I'm sure. The pilot projects was a one time
system that has a lot of benefits for us.
Instead of a reimbursement for some of our
interconnection costs. It just means the utility
pays them directly and then rate bases them.
So obviously it's, that's nice. We don't have
to raise the funds for it. Of course, it's
problems. It's a one time cycle. So there were
six projects selected, and that's great for
those six projects. But then after that we have
to go back to something else. So one of the
things we would like to continue discussing
as a community is when you get a pilot project,
and our company received two of them, the
size of that pilot project is fixed in time
to the date you applied, two years ago, now,
almost. And so if you later expand that pilot
project, there is no provision in the program
to allow you to get more pilot project funding.
So of course you'll have to come out of
pocket for that, which is fair. But one of the
things we think the industry or perhaps the
PUC should clarify is that if a developer invest
additional funds in expanding that private
project that those investments are eligible
for reimbursement under AB 2313. So we would
love to see a proceeding on that someday, perhaps
work together on it because it appears to
us is the key is we're not gonna develop five
clusters and five new injection points every
year. That's just not gonna happen. But we can
expand the ones we have, and we can grow the
industry that way. So we think that's key.
Last slide, second to last slide. I promised
you some case studies. This is three projects
that our company either has developed or is
developing. On the far left is Calgreeen Dairy
Fuels, which began processing some gas and
2018 and injecting some in early 2019. It
interconnected with SoCal gas under Rule 39 the old
standard before the BTU standard was changed.
It was not a pilot project. That system didn't
exist yet. You can see the standards for
injection. It was a 990 BTU standard, which was
very difficult. But we achieved it. And the
critical point of the Calgreen facility is it
was both engineered and constructed by the
owner. So although the obviously SoCal gas was
supervising, providing standards, inspecting,
collaborating all the time, the actual work was
performed by a private engineer and by private
contractors installing equipment that was
approved by the utility. A total time from the
first application of the first piece of paper
to the approved finalized injection was 23
months. If it hadn't been for some startup
issues about sampling, for Siloxane test we
had a very weird thing. If you didn't already
know this, if you have the tiniest bit of
silicone based oil in one piece of equipment on
one part of your project, you will fail Siloxane
test. That's all it takes, a little bit
getting past to seal. So it took us a few months
to figure that out. We had to stop out the
silicone based oil for natural oil, and then
we were able to pass the siloxane test and
otherwise it would have been perhaps 19 months.
Something like that. And you see the cost
there, a million seven. Moving one column to the
right, Lakeside pipeline is a facility we're
developing in near Hanford, Kings County,
California, that is also connecting to SoCal
Gas under the newer version of Rule 39. It has
been selected as a pilot project. Now you see
the standards there are more or less the same,
although there's been a new change in the
BTU requirement. That project's engineered and
constructed by the utility, and that is no
fault of anybody. But just the nature of these
things is they take time. It looks to us
like it's gonna be 35 months between the first
application of the first piece of paper and
the date we go online Commission installed. Now
they're all things were all working together
on improving, but that looks like what the
schedule's gonna be. Some of that is because
the project originally started without pilot
project funding and then had to switch over.
Darryl Moss: And so we were pushing the project as hard as
we possibly could. We're paying all the fees, signing all the
contracts, even though we knew it Might get selected for Pilot
project. We were hoping that that would cause the project
to move faster once it was selected for pilot project, and
perhaps it did. But it's all brand new program, brand new
standing up, so hard to accelerate that. We'll see how it
does. Finally, Merced Pipeline on the far right. That is in
Southern merced County. That's connecting with PG&E. And it's
actually connecting to PG&E through a third party private
pipeline run by California Energy Exchange. So that's kind of
all three of us working on that one. That's also under their
newer version, Rule 21. It's also selected as a pilot project.
You can see the standards there. It appears that we're about
on the same schedule, 35 months. It's hard to say. We're
waiting for someone to impress us and speed up the process.
Darryl Moss: It had the same issue that we had initially
applied, under this standard Rule 21, and then later transition to
pilot projects, so that may have delayed some of the process. So
but we love these programs. They're very excellent for helping
us deploy more and more of these projects. But the speed is the
key. Questions on this before I go to the last slide? Or maybe
I'll hit my last slide and then you can ask questions. You see
the project costs are similar between the two utilities. The
standards are similar between the two utilities. It's really just
a question of, you know, working through the process and everyone
learning as fast as they can. Our two recommendations for the
tariff and I mentioned them earlier during the robust Q&A, I
believe it was called, was first of all, the standard, the narrative
section, says that we're gonna use the interconnect collectible
system upgrade agreement. That caused us significant delays on
our first project at Calgreen. First of all, establishing a
collective, or a what did you call it, a collectible takes months.
I don't know why it just does. Perhaps that could be sped up,
but we just couldn't get that paperwork done, which meant we
couldn't procure equipment, which means we couldn't know the whole
daisy chain of cause and effect. And so that system works slowly.
Perhaps it could be improved, and then the warranty provisions,
as written, were not possible. They couldn't be achieved. There
were no warranties available anywhere in the industry that
would meet the requirements in that. And so that was fixed by one
time advice letter from the CPUC, which we're very grateful.
Everyone worked diligently to make that happen. As I heard it from
Jamie earlier, it sounds like PG&E is working on changing the
standards where the warranty requirements for a self build, which
is what this was, would be the same as the utilities' own warranty
requirements. And if that's done, that would work perfectly. So
we think that's a great idea, just needs to get implemented.
Darryl Moss: So we're all heading the right direction
here, finally, on self designed, as I mentioned
earlier, it seems to us not every project is gonna want
a self design. It may not even be the best way, and
maybe in the future, that the utility design option
is superior in every way. But all I can say is from
the one project we've done that was faster and we'd
like to make sure we keep that option very brightly
highlighted as an option that the interconnector
always has. We had to push fairly hard to insist that
we did have the right to self design and a self built
because there were some folks at the utility of
said No, you don't have that right And we had to go
back to seep You decision, 07 to 8 to nine there,
which says we do, regardless of what the tariff says,
that is the right of the interconnector. And so it
ultimately that got done and that was done well and the
team worked well together. But we think it will be
very important, particularly in Section F, to see
there, that it's very clear that I know we have to work
on these interconnection agreements and everyone has
to publish them. But there has to be no ambiguity
that that is a right of the of the utility interconnector
the customer provided they followed the design
specifications, oversight inspections, et cetera that
that has to be a right open to them, if for no other
reason than it gives people a choice, which keeps
everyone motivated to move quickly. So that's ah, say
at the bottom interconnector sole discretion toe to
select the self build self design option should be
explicit in this state white terror. And that is the
end of my presentation. Don't take any questions.
Jamie Ormand: Go ahead. Question and answer time.
Unknown: One of your previous slide that showed the three columns? Yes, that
one, on the Merced pipeline oxygen is at
0.10%, the other is at 0.2%. Why is that?
Darryl Moss: Those are the pre existing tarrifs the
two utilities have. It's not a killer. Obviously,
we would like to see it 0.2 I don't know if that's
under consideration, but we can meet 0.1 as well.
Jamie Ormand: Anybody from the utility? You
wanna have a comment on that for thinking about
how the future could look. You're all still here.
Everyone is moving very quickly. All right,
Jamie Ormand: Come on down, Tom. All right.
Tom Henz: Congratulations on the speed and getting all those installed and
getting the injection point. On the Merced
one for the dairy Pilot. If you had the
third party interconnection in place and all the rules clear, how much time would
have been saved, do you think it would be directly through the third party?
Darryl Moss: Great question. Our process,
if there was no utility involvement, takes
at least 18 months to build. So simply because
SEQA takes that long, gas procurement
takes that long. And that's from the first
piece of paper, not from construction and
contracting. If we have been able to inject
directly into the third party pipeline and
they'd have been able to receive it immediately
on day one, we probably could have
shaved a year or more off the timeline. As it
is, their facility needs to be upgraded to
meet the latest biomethane standards, which
is gonna be paid for by the pilot project,
which is awesome. The pilot program is great.
Just the speed, speed is what matters.
Tom Henz: And also, even though the the current pilot program
doesn't appear to allow expansion after you submitted,
would you not be able to apply also for the bio methane
incentive as well? Or there Is there a conflict with that
Darryl Moss: as we read the bio methane
and send it there is not a conflict,
but it's not entirely clear. It would be nice if someone were to clarify that as
we see it, any expansions would be eligible.
But I'm not the expert. And I'm at
risk unless someone clarifies that for us
that speaks with the voice of the CPUC.
Tom Henz: Thank you very much.
Jamie Randolph: This is Jamie Randolph from
PG&E. So I want to go back to the question about
the different quality. In the pleading that we
submitted with the draft rule, the proposed rule
if you go to, there's a section that talked about, Section
B, little D, renewable gas quality specifications update,
in the section of retention of each utilities historical
gas quality specifications. We talk a little bit about why
it is that we have different quality specifications and it
has to do with the California production that has been in
place for a long time, and the gas that we get from in the
different territories, it has different specifications.
Jamie Randolph: And so we have to protect our
pipeline based on what's coming into the system
to make sure that the safety of the pipeline is,
the integrity of the pipeline is still. Carol ?
Jamie Ormand: Carol, you want to come down, please?
Jamie Randolph: The oxygen in the C02 specifications.
Unknown: Where you asking about the oxygen just or CO2?
(inaudible from audience)
Unknown: Yeah, the oxygen, too. Both of
those are gonna in the presence of water.
They're gonna accentuate any corrosion? So,
um, and CO2, that limits been, both of those
have been in place for many, many years, and
those were to protect our pipelines from
corrosion. We do have areas where we had more moisture. California has. So you're
Unknown: setting these limits for that reason? So why they're
different? The oxygen, I can't speak to that, really, why it's 0.1.
And theirs is 0.2, they might argue they wish theirs was a 0.1. I
really don't know. Um, the CO2, though, that protected our system.
Unknown: And by not allowing more two in than we
already had, we were keeping, minimizing the risk.
Unknown: I should say that. You know, the 9
90 The old standard was pretty tough, but the
current standards, both of those standards as
shown there, I mean, they're not that high.
Unknown: A lot of people say California, just
these impossible standards for gas. But we do
some work out of state to0. We work with private
pipelines. We work with municipal pipelines.
It's, if I had a point to an issue, I'm repeating
myself, it's the speed. The standard is achievable
by good technology. It's always nice to have
the standards be a little lower. It's always
nice to have a little more flexibility, but each
utility has to work out their own system and how
they operate it. I'm not an expert on that. The
standards are not the biggest problem. It would
be nice if we had a little more headroom. We
could build these projects a little bit cheaper.
But what we're really looking for as a system
is streamlining, at least from our perspectives
Unknown: As far as the BTU limit, PG&E really doesn't have one, but we
back into a number, using calculations from all the other limits. So,
980. If you were that sort of say, what would be our typical range allowed
would be 980 to 1080. But that's not a limit we have in our tarrifs.
Jamie Ormand: Thank you. All right. Any additional questions for Mr Moss?
Darryl Moss: Thank you very much.
Jamie Ormand: Thank you very much. All right. Moving on,
our next speaker today is Mr Paul Schultz from LADWP.
Jamie Ormand: Get ready, everybody, this is happening.
Jamie Ormand: And the slides are gonna happen
too Here we go. All right. You're not Paul.
Greg Win: I'm not Paul, but Paul is sitting in the audience here.
So we're both with the Los Angeles Department of Water and Power
again. I'm not Paul Schulz, but if this goes really well, you give
all the credit to Mr Paul Scholes. If it doesn't go well, let me
introduce myself. My name is Greg Win. I'm with the Los Angeles
Department of Water and Power. I am part of a team that is working
on 100% clean energy innovations, as well as part of the team that
helps run the operations at the Intermountain Power Project. So
I got this great opportunity to kind of look at two things. The
100% clean energy innovations, at the same time, having this great
resource called the Intermountain Power Project that's located in
the state of Utah. That helps bring energy to California and also
all the different parts of Utah. So again, lucky to be part of a
project like this. And I want to just thank everyone for giving me
this opportunity to highlight what we can do at Intermountain Power
Project in terms of renewable green hydrogen. And it was great
to hear the conversations this morning about renewable gas and how
that includes green hydrogen and how we can inject it into the
pipelines. And I want to thank the joint committee for putting in
that effort. So with that, I will just go ahead and get started. So
what we're here to talk about today is with the passage of Senate
Bill 100 in California, the state mandated a transition to 100%
clean energy. So at DWP, we're now faced with this challenge of
providing this clean, zero carbon, reliable power to our customers
by 2045. So the Intermountain Power Project, we feel, is going to
be essential to reaching that goal. And that's what I'm here to
talk to you about. How is it that this project, which is currently
a coal project, how is this gonna help get us to that 100% clean
energy future that we're all envisioning? So before we get into what
the Intermountain Power Project is, I just wanted to talk about
the two big initiatives that we're looking at in Los Angeles, one
of them being the Clean Grid LA Initiative, and then also the
Greg Win: LA100 study that we are currently involved in to get
us to what it's gonna look like in 2045 and how we can get to
that clean energy future. So first thing I wanted to talk about
is what is the LA100 study? So we were tasked as a department,
in July 2017, to begin a research partnership with the National
Renewable Energy Laboratory, NREL, to see what it would take
for us, as a utility, to get to 100% renewable energy, what
investments we would have to make what, looking at different
scenarios, different load profiles to get us to that point.
And so we're engaged in this study. As it stands today, we're
working towards getting that study out, and seeing what it is
actually going to take for us, as a city, as a utility, to get to
the 100%. So some pretty exciting stuff here and it's, that's
part of our responsibility now, to get us to that goal. The other
part of it, which was the Clean Grid L. A. is back in February
of this year, 2019, our mayor, Eric Garcetti, announced his
decision to accelerate DWP's transition away from fossil fuels.
So that meant, so several of our our ocean or once through
cooling units, which are ocean side units would have to be
replaced or offset. That generation coming from those units would
have to be replaced or offset by 2030. And so that accounts for
approximately 1600 megawatts of natural gas generation that
we're gonna have to now replace. And so where we now have two
things that we're looking to do here, we can no longer be on the
natural gas units that we have along our shores, and we also
have to figure out the investments without those units there
and how to get to that clean energy future in 2045. So you see
in this little visual here. It's the confluence of these two
initiatives that's gonna take us to our target of 100% clean energy
by 2045 as well as a carbon-free utility by 2050. So now how
is it that the Intermountain Power Project, IPP, can help us get
to that? Before I get into that, lets, what is IPP? So it's
Greg Win: the Intermountain Power Project. A lot of people like
to call it the Intermountain Power Plant, but it's actually a
project consisting of three things. So it's located in central Utah
in a city called Delta. It's about two hours south of Salt Lake
City, so it was originally built in and put into operation in 1986.
It was two coal fire units with the capacity of 1800 megawatts.
So that's part number one of the InterMountain Power Project. The
other two parts of the project are its transmission systems.
We have two transmission systems that are connected to the power
plant, the STS, which is the Southern Transmission System, that
brings power into Southern California through an HVDC, high voltage
direct current system, capacity of 2400 megawatts, from Utah
into Southern California. And then there's also the Northern
Transmission system, which is the NTS, that wheels power from Nevada
to Utah, and vice versa. Currently we're interconnected with 370
megawatts of wind generation. So there is some renewables that's
coming down from that area, as it stands today, coming down the
STS. The project itself is not just LADWP. It's also made up of
different participants in both Utah and Southern California. 35 in
total. Six of those participants are from Southern California, and
today the plan is, in 2025, these coal units are going to be
dedommissioned replaced with a natural gas system that we're planning
to put in at the same time in 2025. So going into what it's going
to look like, it's called, we call it the IPP renewed, Renewal
Project. That project is going to be 840 megawatts of natural gas
combined cycle generation. Was originally 1200. We decided to
pull it back because for various reasons, we decided to reduce
to 840. We have an estimated capacity factor of 68% that we're
shooting for. Construction is supposed to start in January 1st of
next year, with the completion, commercial operation in July 1st
of 2025. In addition to replacing the natural, the coal units
with the natural gas combined cycle generator, we're also looking
Greg Win: at replacing part of the Southern Transmission System,
which is the 2400 megawatt high voltage direct current system,
and replacing the converter stations on either side. And so we have
completion. We're looking at April 1, 2026. So with the upgrade
of the gas plant, we also have to do some upgrades on the two ends
of the transmission system to ensure reliable operation of that
plant. We decided to put this this project in place for a couple
of reasons. We know that we have to get to this 100% goal, but we
also understand that there's reliability. That's part of our duties
as a utility. So reliability, having dispatched energy coming
from this and from that generator, less reliance on the issues, on
some of the facilities that we have, are having issues with, in
Southern California, namely Alisso Canyon. And you know that first
point here, it's, we're gonna need it, and I'll show you why we're
gonna need this plant to help us get to that 100% renewable goal.
So at Intermountain Power. we have a lot of different resources
that are going to help us unlock this potential that we have for
green hydrogen. So I've named them really quickly here. We're going
to need renewables, of course. But that's the only way you're gonna
be able to generate this green hydrogen. We need transmission.
We need a way to push that energy. We have that. Land and water.
We need land to build these facilities for electrolysis, for
storage, and the water associated with the electrolysis. And we
also have something that's very unique, which is our salt dome. The
Intermountain Power Project, the piece of land that we sit on, sits
on top of this unique geologic feature of a salt cavern. We can
utilize that salt cavern for storage of green hydrogen. And of
course, we have our people there. We have a very talented, very
technically sound group of people that run that plant. And it
would be great if we could utilize that expertise because they've
been running the plant for so long and been doing such a great job
doing it. So as I go into this a little more into detail. Where
Greg Win: IIPP sits currently is this confluence of renewable
energies. We have solar in the area. We have geothermal, we have
wind resources. And so we all have all these renewables now that
we can utilize to help with the production of hydrogen. As I
mentioned earlier, we're currently interconnected with 370
megawatts of wind generation. We also have a path for geothermal
projects. Currently, in our own interconnection requests, we have
2300 megawatts worth of solar interconnection requests. And then
also, there is some talk of going into a project, a wind project
in Wyoming, for 1500 megawatts. That's currently on the books.
So with that renewable energy and with the potential of green
hydrogen and generation from that green hydrogen as a fuel source,
we have to have a way of transmitting that energy. Luckily, we
do. We have the Southern Transmission System, as I mentioned
earlier, and the Northern Transmission System. So we can utilize
these two systems to move that energy into Southern California
and different parts of Nevada and Utah. One of the key features
of these transmission systems is that they're bidirectional,
meaning we can move it from Utah to Southern California and
Southern California to Utah, meaning if there is over generation of
renewables in Southern California, we can bring that back up into
Utah to help with the generation of renewable hydrogen. As I
mentioned again, earlier, land and water. We have an abundance
of land on our property, with the about 4000 acres of land, we
currently have a coal plant that's sitting there that's gonna be
replaced by a gas plant, which takes significantly less land.
So we'll even have even more for additional projects like this
green hydrogen project. The site is fed by Utah's Severe River,
and so originally when this, when the coal plant was planned, it
was planned for four units, and it's right now, currently, two
units, but when the water rights were secured, we secured enough
for four units. So there's there's abundance of water that we
Greg Win: can use in the production of Green Hydrogen. So we have
that as well. And then we also have this one of a kind feature
that we sit on top of, which is the salt domes that we can use to
store hydrogen. It's been shown to be an ideal medium to store
hydrogen. It's something that's been shown in the Gulf Coast, the
Gulf of Mexico, and so we're lucky enough to have one in the
Western United States so we can utilize storage on site instead
of having to deal with the issues of transportation. And then
again, as I mentioned, we have our Intermountain Power Service
Corporation, which is a group of people, engineers, operations,
maintenance and technical staff that have been running the coal
plant for 30 years, have the experience, not only in coal but have
been, have enough of skill sets and technical ability to help us
push forward into the gas plant and hopefully into a renewable
future on that site. So currently we have over 350 employees there.
They helped put IPP as one of the best run coal plants in the
country. And we expect that doesn't, that's not going to change
when we change to a gas plant or something else on that site. So
to summarize some of the things that, you know, in terms of our
resources at IPP. How it is that we can get to that green energy
future. I've just listed here what are the challenges with green
hydrogen? It's the availability of renewables. The transmission
resources. Transmission, as you all know, is very difficult to
build anywhere. And speaking about California, it's really gonna
be difficult to build more transmission here. Luckily, we have
that. Land water needs, storage and transportation, and the threat
of these emerging technologies, and how they're changing so
quickly. Solutions to all five of these we have at IPP. We have,
we're centrally located in what we call the renewable hub on the
western, the Western energy grid. We have the two large transmission
systems. We have abundance of land and water. We have the
underground salt caverns for storage. So to alleviate the need
Greg Win: for transportation. And of course, we have our great
people at Intermountain Power Service Corporation. So in terms
of what we can do at IPP. We have a great opportunity here and
something that we would like to capitalize as a utility to get
us to that green energy future. Some of the projects that I wanted
to highlight that we're currently looking at at IPP to utilize
those resources, we have a couple that I wanted to highlight
today out that I think are gonna be be essential for us. Number
one. We have something called Compressed Air Energy Storage.
So this is basically, we're taking the renewables, of the over
generation of renewables, taking that and storing that as compressed
air within our, within the salt cavern, and then running them
through on an expander on a generator to create energy using that
compressed air. Currently, the technology is natural gas, but
there is a vision for this project to go to 100% hydrogen. And
so this is one of the projects that we're looking at, a pilot
project that we have, that we're currently looking at, for 160
megawatts of compressed air energy storage. The one that we're
also very excited about is this hydrogen fire generation. So if
we if we can produce hydrogen on site, what can we do? We can run
it through those new combined cycle units that we're looking to
put in place in 2025. And so we're looking towards the future,
and day one of commercial operation, we will be able to burn
hydrogen through those generators, a blend of that with natural
gas based on the responses to our request for proposal from our
manufacturers. So something that we're also, we're very excited
about. So going that, going into that a little bit more, when
we had originally come up with this project, we weren't looking
into hydrogen. It was something we were going through what we
would call, at that time back in the early part of the decade,
was a conventional REpower. We're gonna take down the coal unit.
We were gonna replace it with a combined cycle unit. As the
Greg Win: project progressed and as we saw more and more,
this push towards getting to the renewable future, we saw an
opportunity to take what we were doing at IPP and change course
a little bit, so that we could add the capability of burning
hydrogen in these advanced class combined cycle units. So the
three manufacturers that we do have now, that we're currently
in negotiations with, and have responded to our RFP are GE,
Mitsubishi and Siemens, and so we've listed the models
of their advanced class combined cycle technology. All of these
units will be compliant with SP1368 in terms of emissions.
We actually got approval from the California Energy Commission
in November of 2018 to proceed with this project. So all
three of these manufacturers have the capability of burning
hydrogen through their units. So we saw an opportunity to ask
them to provide information when they responded to our RFP
so that they could showcase to us what their capabilities
would be in terms of burning hydrogen through their machines.
So in our RFP, we outlined a lot of requirements for them.
How would they help us get to that renewable future. How would
we, how would they help us get to burning 100% hydrogen
in those machines? So we wanted to start. We wanted to start
first, what do you have now? What's your capability of burning
hydrogen in your machines today? And we gave them a blend
of 20%. We didn't want to go too far beyond that because
it might be too difficult. We thought 20% was reasonable. So
tell us, GE, Mitsubishi, Siemens, what can you do to operate?
Describe to us the capability of your equipment to burn a
blend of hydrogen through your system. Secondly, develop
a plan for us to show us how to get to 100% renewable, 100%
hydrogen by 2040. And not only how do you get there? What
modifications are needed to get us all the way through the
balance of plant and provide us with some value engineering
Greg Win: so that we can avoid any major
modifications in the future. What can we do
today to avoid cost later knowing that we're
trying to get to that burn of 100%. And
then, you know, being that this is new to
everybody, what are the tests that we need
to demonstrate that we can get to that 20%
at least when we install these machines?
The project now, well, the renewal project
that we have for the gas, for the gas plants
is going to require fuel transportation.
So I know it's a little hard to see on the
screen here, but, does this have a pointer?
So Intermountain Power sits right here. And
so this red is is an existing gas pipeline,
so we would need a lateral off of this
system to get into into our plant. So as
part of the project, fuel transportation is
something that we're looking at as part
of the project. And so right now we're in
negotiations with a fuel transporter, and we're
hoping to get that approval by the end of
this month. So part of that transportation
agreement is to provide a minimum of 140,000
deca therms per day until 2045. And so this,
for us, is a minimum that we have to take
knowing that in the future we're still
trying to get to hydrogen and blend hydrogen
on site. This is something that we're committed
to, both on the minimum transportation
side and on the hydrogen side. So this is
going to be part of a challenge for us
Greg Win: because, you know, as we blend hydrogen,
we still have to take this 140 decathemrs a
day, as part of our agreement. And so as we get
into, as we get into the plant where this is,
this is where we're planning on connecting to,
I'll point this one on this too, for you on this
side, that's our interconnection points. And, you
know, this is the current plant, as it's as it
stands today, the generating units are here, and
then the additional infrastructure with the coal
plant is here. So, as you can see, much of this
is not going to be needed anymore. In the future,
our footprint is gonna be much smaller. So does
again provide opportunity for new projects on site.
So part of the reason why we're here today is
we wanted to talk about, you know, if renewable
hydrogen is being expanded through external fuel
supplies, this will be a significant impact on us
as an end user because it's going to affect how we
run our generators. And it's going to affect how
we, how much we can blend of our own hydrogen, what
affects those might have on, on our performance,
on operations, and even on the warranties on the
machine. So I wanted to run through a little
bit of, and this is, I'm sorry. This is a bit
hard to see because of the gray, but this is a
normal flow of gas flow. If you were looking at
100% natural gas through our system. So you have
natural, this is, this is what I'll say is our
meter. This is IPP. And this is on the left side is
the supply side. So once it gets through our meter
and once it gets to us, we have to go through a
Greg Win: fuel fuel gas treatment, which is to
get the gas at the right quality. So we can burn
it through machines. This year I know is, again,
sorry that this is a little hard to see, but
this is basically the turbine. So you would take
the gas, go through fuel treatment, and then burn
it. Simple stuff. But when you add hydrogen to
the mix, it's not as simple as just blending it
and then pushing it through, pushing it through into
the turbines. It takes a bit more infrastructure
that we have to put in to be able to do that.
And so again, this is if the supply is 100%
natural gas, we would bring our own blend of
hydrogen, whatever percentage that is by volume into
the mix. Going from here in the mixer, having
it sit in the gas holder, and then here the gas
chromatography. This is basically a piece of equipment
that will tell us what that mix actually is
to verify that we do have a mix that's safe. We're
going 20%. This will help verify that we are at
20%. Same thing, going through a gas field treatment,
field gas treatment, and then here the calorie
meter to verify the heat content of our fuel
before it goes into the generator. So it's a bit
more involved in just adding hydrogen to the mix.
So there is some extra work that we have to do,
which is again, what we had asked for when we
talked to the manufacturers. The tricky part now
comes in when you have to, when you have a natural
gas blend with hydrogen coming from the external
source. So if we're talking about what we were
talking about earlier, if there was a gas blend,
Greg Win: what it's gonna take and how, What?
How do we verify that, you know, what we're
getting is going to be adequate for us to burn
through? If it's outside of the ranges, the
operational ranges. You know, that's gonna
have, again, some significant impacts on our
burn. So one of the things that we do ask from
the CPUC is to really start, we want to just
have the idea brought up today that it has to
be verified what we're putting through the
system and, because it's going to have a major
effect on the end user. So, you know, I'll
just kind of quickly go through this, you know,
we have storage. Storage is one of the unique
features that we have at IPP. Not only can
we burn renewable hydrogen, but we can also
do something we're calling seasonal shifting.
Now we have energy storage that we can, we
take the renewables, we store it within the
caverns, and we can have it there, for a burn
later and we can shift that energy that we curtail
one day and use it through burning through
the generators further down the road. So, in
terms of the scale of what we could do with
hydrogen, you know, hydrogen has a much larger
energy storage potential then, let's say,
batteries and compressed air. So this is
something that we think is unique and and very
exciting for us in terms of storage. You know,
if we have a four million barrel cavern, which
is a typical size. That's the size of, that's
equivalent to 200,000 hydrogen buses, one
Greg Win: million fuel cell cars and 14,000 truck trailers for delivery. So
because we don't have to deliver, we don't have to move the hydrogen. That's
a big plus for us. You know, this is really just to highlight the scale of
the storage, you know, if we're looking at the combined cycle at a capacity
factor of 50%, it gives us about 10 days of storage that we can burn through
the system. So it gives us 10 days of hydrogen that we can use if we're
talking about 100%. So to give you a scale, that's 84 times the storage
capacity of a 1200 megawatt hour battery system. So some pretty big, pretty
big stuff there. You know, this is just a quick example. You know, if we were
gonna burn 30% hydrogen through the generators how much renewable energy
we would need. So this is just some numbers that I just wanted to throw out
there. But bottom line, we need about 538 megawatts of renewable energy at
the capacity factor of 32% to get us to that 30% by volume Natural gas fuel
mix. This here just really talking about what, one of the resources required
something. According to that example, before, if you have, you need 27 acres,
which is really not much for us. In terms of land, the amount of water
Greg Win: required again, we have plenty
of water to do it. So that's not gonna
be an issue. You know, the example that I gave was 30%. This is you know, as we
get 200% it's gonna be, as a technology
progresses, we'll have a better idea what
that's gonna take, but again, that was
just a quick example of what it would take
for something as small as 30% for our
system. This here is just a timeline that
we're looking at 2045 is the big date that
we're looking for. So, you know, that's
that's really what we're shooting for. There's a couple more details in here.
2025 is when we shut down the coal plant,
we bring natural gas on online. Here,
we're talking about emissions. You know, this is the red of the coal. As we move
forward, we're gonna see this sharp drop in 2025. Because, of course, the cold
comes off line then we enter into natural
gas, which is this blue line, and then
natural gas combined with hydrogen. This is what we're projecting is, of course,
gonna be less. So you know, as we explore
the different opportunities with green
hydrogen and the other technologies around
it, again, Intermountain Power Project
becomes an essential piece of the overall
future. And so again, excited to be
showcasing the capabilities at IPP And,
at this point, I will take any questions.
Jamie Ormand: Thanks, Greg. All right, Who's got
questions about IPP? Don't all speak at once.
Come on, guys. This is the coolest hydrogen
storage project ever. This is actually happening.
Sandy Goldberg: Hi. My name is Sandy Goldberg. I'm an advisor for
Commissioner Rechtschaffen. My question's not about hydrogen, though. I
might have missed this part. Aside from hydrogen, does the project
include compressed air storage? If you just tell us a little about that.
Greg Win: Sure. So there there was an RFP
that was put out from, through the Southern
California Power Purchase Authority, SCAPA,
to solicit proposals for a compressed air
energy system. So, that is the process that
we're going through in terms of, so let me
understand your question. You want to know
more about what air compressor energy is or?
(inaudible from audience)
Greg Win: It's closed now, and so we're still in
negotiations with the selected bidder. And so that is ongoing.
(inaudible question from audience)
Greg Win: So the two pieces are not related, so IPP is its own project.
The compressed air energy system is through a separate, it's through
a separate power purchase agreement with the different participants,
so LA, right now, is one of them, so they're not really related. And
it's, so, they're, it's just a highlight that there's an opportunity
to use the resources that we have on site for different projects, like
compressed air energy storage, like hydrogen storage. So that's what
we're really looking at. They're not really related. In that sense.
Jamie Ormand: Is this a quick question Tom?
Tom Henz: Tom Henz, Seal Team bio-gas. A couple of questions.
The hydrogen is clearly produced through hydrolysis, correct?
Greg Win: Electrolysis,
Tom Henz: Electrolys. My apologies. Uh, is
that gonna be considered a renewable fuel?
Greg Win: Yes, because it's coming from a renewable
source. The electrolysis will be powered by renewables
Tom Henz: All from solar?
Greg Win: from solar, from wind.
Tom Henz: Solar and wind? And what is the pressure
that it will be delivered through the system?
Greg Win: I think I have it on one of these slides here. I think. Or maybe
I don't have it. But I mean, typical cabin pressure is about 3000 p. S. I
Tom Henz: Okay. So, through the natural gas grid,
if you deliver it, what will be delivered at?
Greg Win: if it came through the natural gas system?
Tom Henz: Right.
Greg Win: that I don't have the answer to that.
Unfortunately, I don't know what that would look like.
Tom Henz: my question is that would hydrogen long run be able to be shipped
or transported and be used in the natural gas grid system in the future?
Greg Win: I hope so. But, I mean, that's, we're the
end user, so, I mean, it's, if it gets put into the
natural gas system, I mean, that's, hopefully, it can
be. I mean, that's something that we would welcome.
Tom Henz: Okay. Thank you.
Jamie Ormand: All right. Thank you very much, Greg. I appreciate
your time. Okay. Next. Heidi? Will you please come up? Also, these
are very fascinating presentations, but as always, your time to
speak is less than we want, so let's keep it consolidated, please.
Heidi Lim: Good afternoon, everyone. All
right. Oh, thank you, somebody said Good after,
thank you. I know, it's hopefully, we'll take
a little turn and talk a little bit about
carbon dioxide, which is related to the methane
in our context, in this context. So I'm
Heidi Lim. I'm the chief of staff at a start
up in Berkeley called Opus 12, and we have
developed a technology that recycles carbon
dioxide into, basically, petro-chemical
building blocks like methane and others as well.
And we do that by taking basically carbon
dioxide and water into our unit and then using
renewable electricity to split up those
molecules and rearrange them in the presence
of a metal catalyst membrane to create new
chemicals, basic chemical building blocks that
are carbon based. And oxygen is a byproduct
of that process. So, I think, so at scale.
This can address up to three billion tons
of carbon dioxide every year and touch upon a
$300 billion petrochemical sector. Just by
the molecules that we know we can impact
better today, usually produced from petroleum.
I know we're talking a lot about reducing
emissions today, but I encourage you to look and
think more about also negative emissions
technologies, like ours, and also considering
that the IPPCC report, that 1.5 degree report,
also said that we need negative emissions
technologies to not just reduce the emissions
we're putting in the atmosphere but
also, pull down the CO2 that's already there
and other greenhouse gases that are already
in the atmosphere. So we got our start at
Stanford University. Kendra and Tasha on the
left and right here are two of our co founders,
and they were two graduate students at
the JarameaLab, which is a leading catalyst
lab at Stanford. And they were the first to
grad students working on CO2 electrocatalysis
or using catalysts to turn carbon dioxide
into new products. And they made some key
discoveries that are still used in many labs
across the world today. They published a
pretty important paper that showed there are
16 different chemical products that could be
produced through this process. And you can
google that report if you're interested in
looking further into it. They partnered with
Nicholas Flanders who is our CEO. He was doing
his MBA at Stanford and getting his Masters
in Mechanical Engineering, and they decided
maybe there is something we can do with
climate. We can address some bigger challenges
if we can commercialize this technology.
So back, earlier this decade, we were part of
the Cyclotron Road Program, which is a DOE
funded program that enables science-based
founders to incubate their technologies and
make their first prototype at the Lawrence
Berkeley National Lab in Berkeley, gives them
an ability to continue working on that project
and have funding for it. And so we were
Heidi Lim: able to produce our first prototype.
Since then, we've grown the team, and we're
many more people in the lab. We're still in
Berkeley, California, but we're not at Lawrence
Berkeley lab anymore. So we are focused right
now on producing three different chemical
products from carbon dioxide in one single step.
And those are carbon monoxide, or sin gas, sin
gas being a combination of hydrogen and carbon
monoxide, ethylene, and methane, which is why
we're here today. And just a quick overview of
those molecules. Carbon monoxide sounds kind
of silly, but it's actually a very important
industrial gas. So if you're wearing glasses
today, there's a more than half, 50% chance, that
you're probably wearing polycarbonate lenses.
If you drive a car, it has polycarbonate all over
that car and CO is a basic building walk for
those materials of as well as foams like the
foam in your running shoe or foam in furniture
that you're sitting on. And at the large scales,
we can actually produce jet fuel and other
fuels from carbon monoxide or more specifically
sin gas. So that combination of hydrogen and
carbon monoxide. Ethylene is the basis of most
modern plastics. So, you know, electric vehicles
are still gonna continue to use plastics, and
other applications for plastics will still
continue on. And so we're gonna have to figure
out how to displace petroleum and in those
supply chains. And of course, methane. The major
case, there, is around bio gas, and bio gas,
typically for, we're talking about dairy operations,
but landfills and waste water treatment
plants and whatnot, they usually will have, the
bio gas will be 20 to 50% carbon dioxide. And
so today, often not CO2 is separated out and
vented. What if we can actually take that
greenhouse gas that today we are still venting
and turn into additional methane? Well, that can
actually be very, it could be very beneficial
to the producers of the bio gas as well as our
greenhouse gas emissions. One short way to to
think about what we're doing is industrial
photosynthesis. We're doing exactly what a plant
does where we take CO2 and water in and use the
sun's energy in some form to make valuable
chemical products. And release oxygen. Just like
a plant. So our technology is actually essentially
an electoraliser that, and today we just
mentioned water wlectrolysis is one way to make
hydrogen from electricity. We're taking that
kind of technology and making it possible to
take carbon dioxide as an additional input and
make carbon based products. And so this is a
technology that's existed for decades, and we're
able to leverage existing scale up pathways and
have partnered with the manufacturer, a major
manufacturer of these technologies, in order
to build our systems. And so what you see here
is an actual scale up a pathway for water
electrolisers, and we are, our core technology is
the membrane that goes inside of these systems
and they can drop into an existing pathway.
Heidi Lim: So today we're actually at this lab scale. It's about the
size of a dishwasher, and that's a smaller scale pilot unit. In a
couple years, we will be scaling up to this industrial unit, which looks
like a shipping container. It's number three here, and at that size,
it's the Lego blocks for any larger scale plant, so we can, its a modular
system. We string a number of them together to meet larger needs,
similar to like any water electrolysis as well. So our flagship
molecule is carbon monoxide because there's a lot of lot of things we
could do with it. And we are also
developing ethylene and methane products.
I'll talk a little bit about our CO2 impact. With our technology,
it's actually possible to make a carbon negative material and carbon
neutral fuel. Using renewable electricity. So the way we think about
CO2 impact is in two ways with this darker, with the black part of
this bar, we're showing that, for every molecule, every ton of that
molecule that we're producing, how much CO2 is impacted, in the black
part of the bar is showing how much CO2 is actually consumed in the
process of making that ton of the product. And the gray part is showing
how much of that CO2 is avoided because we're not using conventional
methods of fossil fuel based conventional methods to produce that
product. So for ethylene, it's three tons and two times, so about a
five ton benefit, so it's possible to actually make a carbon negative
material from that ethylene. For sin-gas, if we were using it for jet
fuel, for instance, it could potentially be carbon neutral fuel. And
of course, you guys know aviation is very difficult to decarbonize
industry. So. I just want to talk a little bit about our bio gas
application. This is a case study. It's not something that we've already
built, but it is a business plan that we've looked at with a, it's a
bio gas producer in North Carolina where we'd help them recover about
$2 million of revenue just because of the additional CO2 that we can
help them produce if they integrate our technology into their existing
plant. And so that would be on the order of this kind of megawatts
system, the shipping containers. And we're currently looking into
Heidi Lim: other applications and starting new pilots all
over California and the rest of the country, so open to other
collaborations as well. We have been collaborating with SoCal Gas,
had a lot of support for the past couple years. We successfully
demonstrated a pathway to turn CO2 into more natural gas, so taking
bio gas and turning all that CO2 into more methane. And we also
see it as, of course, a potential to take renewable electricity
that's at access capacity and actually store it in renewable natural
gas. Just a little bit about the process. This looks a little
complex. All it's saying is that you know, there's some CO2 that
today is wasted because we can't use it as a methane. We can't use
it as fuel, and we could just turn it into more methane. We're
continuing this project, now, still with SoCal Gas, but also with
PG&E. We're looking at ways to increase the conversion efficiency,
energy efficiency of our technology still in development, and
looking at other pilots and deployments statewide. And I'm happy to
talk more about alternatives, ways that we're we're addressing
the general challenges around CO2 conversion to methane. It's a
single step process at a lower temperature and pressure to competing
technologies. It's a little bit about jet fuel. Happy to talk
about that later. Looks like I'm running on time, so, yeah, our
customer base is basically companies that need to reduce their
emissions, as well as companies that want to use products out of
carbon dioxide, and have a climate impact and large scale renewables
producers who were looking for new ways to use renewable
electricity. Our commercialization plan, in a couple years, we'll be
scaling up to the industrial system and methane and entholene are
a couple of years. We'll start producing are smaller scale units
around that time as well. And then it's a pretty, pretty fast scale
it from there. Thank you for paying attention. And yeah, is one
of the ways that we're turning CO2 into methane and packing the
photosynthetic power of 37,000 trees in the size of a suitcase.
Jamie Ormand: All right, Any questions?
It's all new cool tech. Go for it.
Unknown: Well, that that's really inspiring. To pack 37,000 trees
in a suitcase. So you're gonna take carbon dioxide and air or
water? Okay. And where is the water going to come from? And what's
the source of the electricity that you're gonna use the process?
Heidi Lim: Yep. So it's, uh, of course, every
every like, deployment will be different.
Heidi Lim: It'll be water from, it could actually
capture directly from the air, but it's just generally,
you know, water for any local system from water or the
carbon dioxide can also come from, generally, it'll be
a point source of emission of CO2. Or it could even be
connected to a, there are new technologies emerging
called direct air capture plants that are pulling CO2
directly from the air. And there's also capture water.
Unknown: How much water will be used? You don't want a system
that's gonna be really water intensive. Pardon me? Water per KW?
Heidi Lim: I'm happy to talk about that off line. I think
that's something that, well, yeah, we can address that later.
Jamie Ormand: Anyone else? Opus 12. Come on down.
Heidi Lim: I think another question to
look at is also, you know, you're looking at
versus conventional processes that take a lot
of water as well and so there's, there are
certainly comparisons to be down there. And
we are working with experts and LCAs and TEAs
to look at that full life cycle because that
is, of course, a very important consideration.
Daniel: Daniel Dodd, the CTO with Sierra
Energy. Are you net producer of oxygen, then?
Heidi Lim: Yes.
Daniel Dodd: Okay, because we're a net user
of oxygen. So I'll talk to you after this.
Jamie Ormand: Collaboration in the workshop. All right. Thank you, Heidi.
We'll be in touch. That's Heidi Lim. Right. Next, Daniel. You're up.
Daniel Dodd: Yeah. Wonderful. Good
afternoon. Thank you for inviting me here. I'm
Daniel Dodd, the CTO with Sierra Energy. I
have a Master's in Aerospace Mechanical
Engineering. I've been working with Sierra
Energy since 2007. And I'm really responsible
for the R&D and now the commercialization
efforts of our gasification system. I was
invited here today by our two project sponsors
and collaborators, stakeholders, PG&E
and SoCal Gas, and ultimately here to give
you another update on a project that we
just completed for them where we were doing
a feasibility study, looking at taking
our technology and a relatively large scales
deploying it for the production of RNG.
Jamie Ormand: I'm working on it.
Daniel Dodd: No problem. Well, I suppose, while
Daniel Dodd: while they're being brought up, ultimately,
the motivation of a lot of folks in the room, especially
that was related to the RNG aspect, know that it's one of
the best ways for us to green the California economy is
by actually injecting RNG into the pipeline and forcing
all of the users to consume green methane without their
knowledge, without them knowing it. And same with electricity
as well. If we can push green electrons in the grid, the
user ultimately isn't going to know it, other than potentially
an increase in their rates. But. So as a result, the
main focus for Sierra Energy as part of this feasibility
study with the SoCal Gas and on PG&E. Again, the motivation
is production of renewable natural gas. Also focusing on
taking waste wood materials, forests, residues, agricultural
biomass, et cetera, that currently maybe open burnt or
potentially going to co-gen facilities for at least
Daniel Dodd: some amount of electricity production. So it's
also gonna help derisk some of the fire issues related to
biomass buildup in California. For those co-gen facilities that
have been able to obtain additional PPAs after their initial
20 year PPAs expired, it's a good opportunity for us to potentially
retrofit an existing facility, bring back those jobs and
produce RNG instead of that same location using the same
infrastructure, almost the same infrastructure, and logistics.
The main focus on this feasibility study then was, you know,
selecting a generic California site. We're working with utilities
in Northern California and Southern. I didn't put this in here,
but it was 1000 ton a day of wood going into our system.
So including the moisture, it's probably about 1300 tons a day
of material received on site. Co-gen facilities can go up
up to that scale, but they're typically in the 400 to 1500
ton a day of material received. So we're at the upper end of
Daniel Dodd: that co-gen siting or sizing, I should
say. The expectation was that it would be 1000 PSIGs, the
injection pressure, and that we would obviously have to
meet Rule 21 and Rule 30. So with, our main focus, as well,
was this to not just be an academic study. We really wanted
to make sure that we were working with proven vendors,
manufacturers of major equipment, and unit operations.
And so in the end, we actually worked with about 50
different unit operations and equipment vendors. Especially
on the backend. We reached out about eight different
manufacturers of catalytic RNG productions going from send
gas through to renewable natural gas. We reached out about
eight. We were only looking at the proven RNG manufacturers.
So it's mainly catalytic, as opposed to some of the
new novel electric K, for example, using microbes. And one
of the core focuses was to evaluate the levelized cost
Daniel Dodd: of fuel production against various factors so
ultimately optimizing our plan to really drive down the LCOF
and provide a baseline study that could go into the future
project development. So the main deliverables for Sierra Energy
providing them through to SoCal Gas and PG&E were really the
feasibility level engineering documents, the standard all the way
from design basis all way through Cap Ex, OpEx and also a final
report, including LCOF analysis and optimization. So our core
IP is really in the gasifier. The unit that basically absorbs
the solid material and converts it into a gas that cann then
obviously be upgraded for additional reuse. So we didn't invent
this technology, it was actually invented by folks from Kaiser
Steel, down in Fontana in the LA basin. It's basically 100 year
old blast furnace, which is typically used in the steel industry
to convert iron ore into liquid hot metal. And the engineers
basically realized that a large blast furnace is basically
a gasifier. It consumes solid materials and converts it, typically
into gas. So we inject oxygen and steam in at the base. We
raise the temperature of the feed up to a peak of about 4000
Fahrenheit or 2200 Celsius, and it's a big counter-current heat
exchanger. As you can, see solid waste is coming in from the
top, in this case for this study it was biomass ag residue, et
cetera. It's coming in from the top, the high temperatures
generated in the base of the gas fire rising up through that bed
of material. So it's a very thermodynamically efficient process,
big counter current effectively occurring in the gas fire.
A large residence time material from the top, reaching the top
of the bed to it, actually making its way down to where it
reacts with the oxygen and steam. It takes a couple of hours.
Quite a large thermal mass, which means it's quite a dynamically
stable system on technology. And we get to such high temperatures,
that any inorganic materials, any metals, dirt, glass,
et cetera, are gonna melt. We're gonna be able to recover those
as a highly alloyed metal and separately, a inert stone. So
again, a blast furnace. Very, very simple. No moving parts in
high temperature zones. So a very robust expectation on the up
time and availability for these types of systems. So we were
incorporated as part of the U. S. Army's Renewable Energy Testing
Center program, which is the former McClellan Air Force base.
We had about four years of operations, where we had a small
PDU, process demonstration unit, that operated for about 750 hours
on a number of different waste materials. We really focused
on understanding our true heat and mass balance of our core
equipment, which is the gasifier, again, solids to initial gas.
We were basically flaring that gas as soon as It was made.
We're working with UC Davis on actually doing the gas analysis
and confirming the heat mass balance models. And Ultimately,
we were driving towards truly understanding what our heat mass
balances were and emissions profile so that we could actually get
a first commercial reference facility permitted in the state
of California. So that activity then lead to funding and
contracts with the California Energy Commission, the Department
of Defense. This is the system of Fort Hunter Liggett, which
is in Southern Monterey County. It's a 10 to 20 ton a day
gasification system. At the moment, we are producing electricity,
or there's a generator on site with, I believe, it's a seaman's
glass core gen, set to take the sing gas, which is mainly carbon
monoxide and hydrogen and some CO2 as well and convert that
into electricity. On the back end of the system, there is also a
Fisher Tropes unit actually supplied by Research Triangle Inc.
The focus for the military has been more on waste being converted
all the way across into electricity. The focus for the
California Energy Commission was waste all the way through to
liquid fuels, and so that facility, it is a commercial reference
Daniel Dodd: facility. We've got a one barrel day reactor.
That will be used to produce liquid fuels as a demonstration,
certainly not at a commercial scale. So then we move back to
the study for PG&E and SoCal gas and so some of the additional
assumptions again, it's a generic California location. So all
the labor rates were assumed for a blended California rate. The
feed material, GTI actually completed a very good study early this
year. Looking at taking a, I think it's a Duke energy or maybe
DT Energy, even, a facility in Stockton and converting that
into a gasification site and we use the same material blend so
that people could draw conclusions directly. Apples to apples.
So it's 40% forest innings, 40% CND, about 20% agricultural
residues. Obviously, we could do it for a number of different
feedstocks all the way through to waste, possibly waste tires, et
cetera. But again, that was the focus for this study was on the
material that is gonna make the most difference to California
from a fire risk element and also from a greening the pipeline
effort. Approximately 36% weight moisture is what's so received
at the gate. We actually would pre dry that with waste heat in
the plant before it goes into our system to an optimum about
20% moisture content. Before it goes into our core equipment.
But again, that's all happening within the balance of the plan.
Utility costs were again working with our stakeholders, we
assume $3 per mmbtu for any nat gas that is procured over the
fence for any of scenarios where we are procuring that gasload
over the fence and any electricity that's required to again be
procured over the fence would be 12 cents per kilowatt hour.
So here's a basic plot flow diagram. Solid materials coming in
top left and ultimately, the renewable energy product, which in
this case in that is RNG, bottom right. Our core IP, is in the
two units in the center, the fast-lock gasifier and fast-lock
polisher. For a system of this scale would probably be looking
Daniel Dodd: to get in materials down to about four inch
minus. It would still typically be two sizing separation
processes like a pre shredding and then a final shredding
to make sure it's in that 2 to 4 inch size material. Then
we will go through a waste heat boiler. Funnel some gas clean
up to meet some of the requirements of the local adboards
and then also the downstream. Send gas to RNG conversion
technology equipment. We would have a separation unit on
site, typically a pays for itself to actually buy that very
large piece of equipment up front, as opposed to buying oxygen
over the fence, which is another alternative for a project
developer in the future. So study execution is mentioned
before, we're really focused on using true numbers from
industry rather than pure, purely being an Aspen based
academic model. And so, yeah, we procured an outsider
engineering firm based in Chicago, ultimately took about seven
months to complete this study, where we were driving towards
detailed specifications sheets and then working with,
again those 50 different vendors in various areas of the
plan to get actual bids and budgetary estimates and down
selecting and optimizing with them. We were able to achieve
the Rule 21 and Rule 30 requirements. I'll talk a little
bit towards the end about the hydrogen requirement, but
that was one of the hardest for us to meet. Just the nature
of the send gas to RNG conversion, catalytic process on
the back end. Reaching that 0.1% hydrogen by volume was
probably the most stringent and most difficult requirement
for us to meet. But we were able to meet them, at least at
this feasibility study level. And the downstream technology
provided was very comfortable. I mean, in those specifications
as well. So the study results, ultimately, as well, also
drove us towards a plot plan. Approximately 17 acres.
Daniel Dodd: Again, it's receiving about 1400 tons a day
on average. Assuming you're not receiving materials over the
weekend, you actually receive a little bit more five days
a week. And there's about 20 days of storage on site, soa
conventional Cogen facility. It's probably relatively similar
in terms of footprints. About 17 acres, 60 to 70% of it is
actually for the feed material reception, handling, storage.
The other 30% is oxygen generation and then the conversion
equipment. So high level Capex then and this is actually showing
a low pressure scenario. I failed to mention at the start
of this. We were gonna be reviewing high pressure operations
on a gasification system and low pressure. High pressure is
operating a gasifier about 150 PSIG. Low pressure was at 15.
And so these, this is the capex for the low pressure, which
is actually slightly more expensive than the high pressure
scenario, but ultimately about $180 million of core motorized
Daniel Dodd: packaged equipment before actually installation
inside plus development cost, PC cost, etcetera, so total install
costs plus or minus 30%, on that, was about $200 million. Obviously
is very highly dependent on the specific site and the specific
companies you're working with. as to that additional installation
costs and project development costs. The core equipment itself
would be relatively stable in cost across North America. Separately,
we're working with UC Davis, actually conducting a life
cycle assessment on our fastox gasification technology. So it was
separate from this study, but we were able to utilize the results
of it as part of this feasibility study for PG&E and SoCal gas.
Ultimately U. C. Davis were looking at a smaller 50 ton today.
So the system I showed a minute ago at Fort Hunter Ligate is about
20. We looked at a 50 ton today, which is our next commercial
scale up expected in the next 24 months or so. We assumed a 90%
up time. As you go up in scale, typically, your up time can
Daniel Dodd: actually start driving upwards of north of 90%.
We're also assuming municipal solid waste where as obviously
for the PGA&E sample study, we're very much focused on biomass,
so ultimately, it certainly wasn't directly applicable.
But we were conservative in using results from it, and even
on MSW at small scales, so it's less efficient is using MSW,
which is a higher carbon intensity than obviously biomass, which
has is almost 100% biogenic carbon. We were still looking
at about 12 to 15 grams of CO2 equivalent for megajoule. U.
C. Davis, I think used $185 per ton of carbon for the LCFS
credit and ultimately that drove towards the LCFS credit of
about 15 to $16 depending on plan configuration. And I suppose,
just going back to a point again, ultimately at a larger scale
and using biomass as a feedstock, carbon intensity, and
especially if you're looking at carbon sequestration and
storage or re-utilisation, would most certainly go negative
Daniel Dodd: as well. If we were to incorporate those technologies
and the fact that we all be operating at large. Okay, rolling through
the last few slides, then, quite a difficult slide to really go
through in detail. But ultimately, the most optimum plant scenario
for us was running a high pressure, which for our core equipment is
150 PSI doing sin gas recycle, which means that any heating that has
to happen within our plant instead of pulling that gas over the fence,
instead, you'd actually recycle some of your green sin gas back
into the process, so for the project specifics, that actually made the
most sense to recycle your sin gas, which would decrease the amount
of RNG you're actually exporting. But ultimately it made the most
sense economically. And what this is showing is that at those scales,
including an LCFS credit about $15 mmbtu, which again is relatively
low. Assuming we're getting paid to take the material again with
gasification, especially high temperature
systems like this, we should
be able to accept waste materials as opposed to procuring biomass.
Daniel Dodd: We obviously show the pricing on there, as well,
if you procure a clean fuel at $30 a ton. But ultimately,
if we were to get paid $30 a ton to receive the material,
we can actually pay the utility about $9 per MMBTU
to take the nat gas away, the RNG away, and we still
break even over 15 years. If we have to pay for the feed
material at $30 a ton. If it was a clean fuel. We could still
pay the utility to take the RNG away at about a dollar
per mmbtu. Again, that assumes an LCFS credit and some other
specific assumptions as well that we can go into offline.
Obviously, conducted a sensitivity analysis on this. So
that was just the simple calculations that Sierra Energy
did using our own tables. We also then used the CEC's LCOF
calculator and ran through a couple of difference specific
scenarios and looked at the sensitivity analysis on that.
And ultimately, what this kind of drives towards is
Daniel Dodd: if we weren't getting any kind of royalty or
payment for removing CO2 and potentially selling that and if
we have to procure the feed material, we're looking at about
$2 per mmbtu to break even over 15 years, so I'm throwing
a lot of numbers at you there, but ultimately, if we have to
buy the material instead of us being able to accept a waste,
if we're not getting any kind of credit for the CO2 that's
removed from the process for potential utilization. But we
are receiving that LCFS credit, we would have to charge
probably about a $1.70 per MMBtu, which again is lower than the
procurement price that PG&E and Semper are currently paying. So,
ultimately, conclusion to this, Then, FastOx based projects
for the conversion of waste wood do exhibit strong project
economics that potentially don't require carbon credits.
Obviously, devil's in the details and it depends on the
specific project. This project was producing about four billion
Daniel Dodd: cubic feet per annum of RNG and if we were to
retrofit all of the existing co-gen facilities in California with
this technology we would probably be able to offset about 2% of
California's current natural gas usage. Obviously, that's just
looking at the co-gen facilities. Obviously, there are thousands
more tons of material out there in California. It's difficult to
potentially obtain that material because the steepness of the
hills or just the remote locations, but again, different project
developers will find specific areas where this technology will be
able to plug in to make a significant difference on top of the
feedstock that is currently going to co-gen facilities. The reason
we support this standard renewable gas interconnection tariff is
ultimately, simplifying, streamlining red tape and documentation
requirements is obviously going to make it a lot cheaper for the
project developer, but also on the utility side as well on. So
overall, it's gonna decrease our cost of RNG production is gonna
Daniel Dodd: lower your cost of procurement off the RNG as well,
which is ultimately gonna drive towards increased project in
technology adoption, and then one final point, which again, is that
for us, it was actually quite difficult, not impossible, quite
difficult to meet that 0.1 percent volume hydrogen requirement.
And I know it's a potentially different topic of debate for a
different session. But ultimately, if we were able to see the
hydrogen requirements increasing, we would be able to see quite
anincrease in yield available of RNG. So the way that we actually
drive down towards meeting that requirement is actually by
oxidizing the hydrogen. But that unfortunately oxidizes some
of your methane at the same time as well. So it's additional
equipment. It's additional oxygen. Which again, if we're allowed
to inject slightly higher hydrogen amounts, up to say 1%, I think
we would be able to, uh, significantly decrease our overall Cap
X and Owl X. Thank you for time. Happy to take any questions.
Jamie Ormand: Thank you very much. Any questions for
Daniel? As we're considering, whether or not we're
asking questions for Daniel, I invite you all the
standup, stretch break for 30 seconds. And then our next
person we're calling down is Michael. Stretch break.
30 seconds. Stand up. Get that blood running back to
your brain. Thank you very much, Daniel. Please talk
to my intern. He works at UC Davis. He's at UC Davis.
Jamie Ormand: All right, Stretch Break is concluding,
and we're going to continue on more cool projects. Low,
zero, negative carbon-intensity projects interconnecting
with system, decarbonizingthe natural gas pipeline
system. More information is coming. Please come back to
order. We just have a few more left. We'll get through
our questions and then I'll let you go. James. Thank
you. Ken. Thank you. All right, Michael, you're up.
Michael Cooper: Okay. Thank you guys very much for
having me today. I wanted to take a, well, first of
all, my name is Michael Cooper. I'm the manager over
the Key accounts team for Southwest Gas. If you guys
have had opportunity to work with me and my team, we're
responsible for working with all the large customers
within all of our territories, as far as the account
management, project inception, as far as project
management, also, so lots of the innovative and new
and cool projects come through me and my team. So I
have a luxury and have been able to see these RNG
projects through multiple different states and multiple
different territories. And I want to kind of come and
talk to you guys today about some of the things we've
seen here in California and some of the lessons
learned and how they kind of diverse a little bit. I
have two different projects that I'm gonna go over,
very, very briefly, and so there's, the scope of work
for these projects and Southwest Gas involvement kind
of very significantly on both of them. I caution you
now and apologize in advance that I won't be able to go
into great detail with some of the specifics related
to the project, as we have in NDA's and some of the
concepts of still being put together in inception.
But I think there's enough public information I could
report on that gives you guys a good flavor about
some of the things that we're looking at and some of
the nuances that we've had to deal with. So the first
project is Rialto Bioenergy Facility, and their kind
of like a waste recycling facilities in Rialto,
California. There was a groundbreaking in December of
last year for new component of this overall site that
Michael Cooper: focuses on taking, I mean,
one of things that was brought up earlier was
organic waste within the state. And so once
it's completed, what they anticipate is going
to be late 2020., This facility here will take
700 tons, yeah, 700 tons of food waste and
300 tons of biosolids within the state on a
daily basis and convert that to renewable
natural gas, renewable electricity, and also
class A fertilizer, organic fertilizer. And
so the way this is set up, it was the
groundbreaking for it. Southwest Gas's involvement
wasn't tied to the interconnection for this,
however, the details of the interconnection
will tie to like three-quarters of a mile,
six inche pipeline that was run to the
upstream provider, and then we have a gas
procurement arrangement with this facility here.
So this is something that I think will address
lots of the issues going on in California,
but also shows that it's a proof of concept,
something for the state to be very proud of,
too. Once it's all said and done, this will
be the largest facility of this type with
in North America, something to be very, very
proud of and hopefully a proof of concept of
other things that's to come. The next one
that's in Victor Valley. Or Apple Valley. VVWRA
Is Victor Valley Waste Water Resources
association. This is a project that's been much
more labor intensive on our end because it's
a much more involved where we're going to be
Michael Cooper: doing gas procurement as well as
interconnection. Currently, they have digesters on
site as three of the five digesters are operational.
But there's a extensive remediation that needs
to take place to get all of the digesters up and
operational to full capacity, but with those current
digesters, you can see they push about 11 million
therms, or 11 million gallons of water that they
process per day. The full capacity of that facility
is up to 18 million gallons of water, with their
three digested that are going through right now,
they're producing 280 million therms, or 1,000,000
cubic feet of gas, on the annual basis, or bio gas,
on an annual basis. They anticipate once you do
get everything fully remediated and up and
operational, you're gonna to see about a 33% increase
in natural production. So that's gonna bump it
up to about 350 to 370 million cubic feet of bio
gas. And so our involvement is involved with taking
the gas away because w're going tie it directly
into our system. In all the various territories,
we've seen different hurdles, and you guys have
been involved with these types of projects. There's
the financial issues as far as the viability the
product. So I will echo the same thing that was echoed
earlier as far as, You know, the additional cost
funds available for these projects. This is a project
that we're seeing they're still going through
getting all of the funding for it, and so that
will be something a great asset to be able to have
for these types of projects, not just in the state
of California, but just in another states. Also,
Michael Cooper: Another hurdle we run into is the
infrastructure and takeaway capacity. And so far
as this site here, worked out very well, because
we have a high pressure line already on site and
we have enough take with capacity to take away all
of their production they want to be able to do.
But I've seen facilities where they have a great
project, but the natural gas infrastructure is
miles and miles away, and so the economics generally
doesn't work for those projects, when you factor
that in on top of all of the other considerations
that go into that. This is one that we've been
working on for a while. Anergia is the one that
they, VVWRA, their board approved for them to be
able to have the partnership to get everything set
up. I believe the way it's going to be worked
out is VVWRA are responsible for the digesters and
Anergia will be responsible for all the scrubbing
equipment and we will have an arrangement to be
able to inject into our pipeline. And so those
are 2 high level projects that we dealt with in
the state. One of them is going through, as we
anticipate having gas flowing into our system within
the end of next year. And then the other one,
we're still working through the details on that,
getting that all squared away, but just want to
give you a general flavors on the things that we
deal with. If you guys have any questions, I know
that we're pressed for time, so I have all my contact
information, there, phone number, email. But
feel free to reach out to us If you guys want to
talk offline. I have cards and we can follow up.
Jamie Ormand: Thank you, MR. Cooper. That was great. That was
wonderful. Any question? Southwest Gas. Mr Cooper. Thank you very
much for coming into town and telling us about this stuff. All
right. Next, let me call down Andy Foster. Please. And thank you.
Andy Foster: Thank you very much. It's kind of like being the speaker just
before lunch, where I'm standing between you and your parking validation.
So we will make this quick. I have the advantage also, that some of the other
speakers didn't have, which is Daryl Moss went ahead of me, and Darryl
and I are in very similar places. So some of my slides I could move through
pretty quickly. Let me start off so quickly with, uh, here we go. AEMET
is publicly funded, a public company, we were founded in 2006 Eric McAfee
who has been a venture capitalists in Silicon Valley for a number of years.
We own currently a 65 million gallon per year ethanol renewable ethanol
facility in Keys, California. It's the largest ethanol plant in the state of
California, one of the largest bio-refineries
in California. We also produce
about 400,000 tons of animal feed on an, every year, which is sold into
the local dairies. And so there was our sort of introduction into the whole
bio gas world. We at the 2018 CDFADDRDP received two grants for our 1st 2
dairies. We're about 80% completed on those. It was 2018 grants, we're almost
done, it's 2019, and we'll complete those in January. We're building a
Andy Foster: 3.7 mile pipeline from the
dairies to the ethanol plant where we will have
cleanup equipment. I'll go into that just a
second, but we're well underway. Phase two will
take us, really, by the time it's all done, we're
gonna have about a 35 mile private pipeline
out in the Series down to Hilmar area. So it's
a pretty extensive pipeline process. So at
AEMETAS, keep remembering to advance my slides.
Sort of look at things in three stages. First
generation, second generation, third generation.
We started off in the corn ethanol business,
which is a very respectable business to be in.
Remember, it's a renewable fuel. I know it
gets a bad rap from a lot of people, but it's a
good thing and as well as bio diesel. We have
a 50 million gallon per year biodiesel plant in
Cacanada, India. Really, where we're starting
to head in now, as though, as the industry has
transformed. I've been in this industry for
now 12 years, and I remember the very beginning,
everybody said cellulosic Ethanol is just
two years away, and it's taking us some time,
but we're actually there. The next phase is
we start moving into renewable natural gas
and lower CI ethanol at the corn plant. So
electrification is a big emphasis for everybody
in the state of California today. We're probably,
in the next two years, going to do about $30
million worth of electrification projects at the
Keys ethanol plant. We use a lot of steam
there, so we're gonna be converting that over.
Andy Foster: It's a great thing. I don't want
to see California kind of go down the path
that the United States was, in the 1970s, when
some of you were old enough to remember sitting
in gasoline lines. So we want to make sure that
we have a balanced approach to that, which
is why biofuels plays a real critical role as
we move forward, and then, third generation
really is when we start talking about cellulasic
ethanol. We announced earlier this year
that we're going to be building a plant in
Riverbank using a similar thermal technology that
the gentleman from Sierra was here. There's
differences, but same general idea to make a low
below zero bio fuel. So if you look at these
two things, Heidi talked about this earlier,
well, it's great to talk about slowing GHG, when
you talk about biofuels, you're actually going
below zero. So we're actually taking CO2 out
of the atmosphere. And that's a distinction
that is sort of unique to many of these projects,
that we're all talking about here today,
and I think it's important to remember, because
again, electrification is the buzzword
in California now. Everybody's about
electrification, electrification. No problem. We're
on board with that. But if that's the only
policy that we pursue as a state, policymakers
are gonna make a huge mistake when there's a
PSPS, an earthquake, and a fire all at the same
time. If everybody has an electric car,
electric utilities of their house, it's kind of
Andy Foster: Armageddon. So we think that
government should do a really good job of creating
an atmosphere and a marketplace where the best
technology, the lowest carbon technologies.
Let the carbon market be the winner in this
whole process and get out of the way. And don't
pick winners and losers because anytime
government's done that in the past, they picked the
wrong one, not picking on government. It's just
let the marketplace take care of it, which is
sort of the point of this whole side, right?
There's a lot of great things out there. We need
a balanced approach. Let's keep a balanced
approach. And so for the folks at the CPUC, I've
been to a few field hearings where it's all
gonna be electrification. There's nothing wrong
with that. But biofuels, other things have a
critical role in here because we remember the
renewable natural gas that we're creating has a
lower CI than a Tesla. So and we're also working
with a large automobile manufacturer to provide
renewable natural gas as a feedstock for
fuel cell technology. So there's just, there's
a real matrix, a nice way for all of us to
contribute to this and for the state to really
level playing field, create a great atmosphere
out there. I was around when the LCLFS started,
and there was a lot of people who said this
was not gonna work. Every single renewable fuel
provider in the United States wants to sell in
one place and one place only. The State of
California. All the ethanol plants in the Midwest
Andy Foster: ship their ethanol to California,
all the pipeline deals with renewable natural
gas are shipping it to California. There's
reason for that. It has become, because the
carbon market closed at $208 yesterday. So that's
that's a great endorsement of the policies
here, so let's keep it up. So we'll quickly,
Darryl talked about a similar project.
We are near Turlock between Modesto and Turlock.
Actually, we're in Series. Right now, we
have about 20 dairies that are signed up. Our
first cluster is gonna be 30. As I mentioned,
we have about a 35 mile private pipeline that
we're putting in. Unlike some of the other
projects, we're actually removed, removing the
H2S at the dairy site. We felt like it was
a safer way to go. And we're also pressurising
our pipeline, taking our cue from our friends
of PG&E and talking to other folks in the
industry. It was a pretty good consensus that
transporting hydrogen sulfide through a pressurized
pipeline is not the thing that's gonna
make our insurance agent very happy. So, but
it makes sense in the bigger picture. It's
a little bit more money for us to do it that
way, but we feel like, the gas do we then
deliver to the ethanol plant where we have our
main cleanup hub will then be giving us the
optionality of either putting it into the
pipeline. We're gonna have a PG&E connect. We're
gonna have a CNG station. And we'll also have
the optionality of using that bio gas to
replace carbon based natural gas at our ethanol
plant. Reduce the C I of our ethanol fuel.
So it gives us a lot of optionality there.
This just shows you there are a lot of dairies
in the Central Valley and this is just a very
small portion of it. This is kind of the
northern part of the valley. Mainly, Merced
and Stanislaus County. I'm gonna skip these
slides. You all know how digesters work. By
this point, you've heard a lot about cow poop
and so we'll sort of go past this. But the one
thing that I would also encourage everybody
in this room who's talked about various
different types of technologies, we're having a
massive capital infusion in the state of
California. There's a huge economic impact. We're
creating jobs all over the place. If you're
building a project like we are, it's hard to get
workers. That's a great thing we should be
talking about that as well. But these are not
only temporary jobs that are involved in
construction, but we're also hiring permanent jobs.
So the the economic impact of green energy.
Again, it's something that I think we all
get caught up in the details of our pathways
and our C I scores, and I think we forget
sometimes to talk about these things. But our
project in the Central Valley is having a pretty
significant, significant impact, along with
Darryl Moss at Moss Energy and some of the other
developers. And then we're all familiar with
the environmental benefits. So just so it
Andy Foster: turns out that many of the many
of the dairies that we're working with are in
disadvantaged communities, and so that's also
providing jobs for folks in areas that don't
have access to jobs or job training. We're
working with opportunities in Stanislas, too, to
create a job training program to help folks who
want jobs for the future, jobs in their own
neighborhood, so that they don't have to commute
to the Bay Area every day. And it's supporting
agriculture. On the environmental side, one of
the other things that we're talking about, every
dairy we work with, we're improving their manure
management practices and their water practices.
So the whole package is not just about mitigating
methane, which is a huge thing. But it's
also looking at all of their other business
practices and trying to help them improve. Talked
about the mitigation. This just gives you an
overhead view real quickly. This is the ethanol
plant in Keys. We're bringing our pipeline in.
We'll have a single fill CNG station and then
connect with the PG&E Pipeline that exists
already right in the back. And you saw pictures
earlier, but various stages. This is the ethanol
plant over here, and there's a finished
digester and sort of what it looks like in
construction. And then, finally, I'll just wrapped up
with a couple of comments about what the earlier
panel discussion. I think when it comes to the
interconnection issue, I view this, as there
should be a higher bar, and I will submit our
comments, I know that's important. But my biggest
concern about this whole reservation processes
there will be developers who are going to go
in and grab those spots and do nothing with
them. Happens with other state grant programs.
We've seen that, and so I think there ought to
be a higher bar. I think we should probably put
some level of completion of your project or
financing that would require a certain level of
demonstrating that those projects were going to
go forward in a timely manner, and I would not
put three years is not timely to me. Should be
a year or two. Of course, the utilities have to
perform better, too. I think Daryll touched on
it earlier. It's too expensive and it takes too
long for us to interconnect. Now that I know
our experience with PG&E, great people. But I
know that this is only, what three or four in the
whole state that have happened from bio gas. I
think there's only three or four interconnections
that have happened. So the utilities are learning
how to do this as well. I would say a year
from now the system is gonna be slammed because
there are a ton of projects that are gonna
be coming on, so we have to figure out a way
to work together in order to make this process
more repeatable, faster, and cheaper. So I would
agree with those points and then, as far as
the CPUC, just continue to support these programs
that help the developers bring this this
renewable natural gas into the pipeline and to
the citizens of the state. Thank you very much.
Jamie Ormand: Thank you very much. Yeah. Come on down.
Andy Foster: They won't validate your parking. If you
get your car is still there. Sorry, San Francisco.
Unknown: Question. I saw that you were doing your own
high pressure gathering line. If there's another biomass
project and it meets the rules and specifications, would
you allow them to interconnect into your gathering line?
Andy Foster: I certainly think we would entertain that. If
somebody had in adjacent area that was developing a project,
Unknown: Correct. Maybe an alternate feedstock or the same feedstock?
Andy Foster: As long as it meets rule 21,
which ultimately is where we have to be
for a specification. I don't see. Yes, of
course. We would definitely entertain that.
Unknown: Thanks.
Andy Foster: Okay. Thank you very much.
Jamie Ormand: Making more connections. All right. Final
presentation, Keen, you and your team are up. If you'd like
to be at the podium. Great. If the team was to come behind
the desk here and you can all come up, whatever you prefer.
Keen: Please come out. I did, if I look a bit tired, I
am because I flew about 18 hours to come over to give this
presentation. First of all, I like to thank, I mean, Jamie and
the CPUC to give me this opportunity to present. And I think, I
hope, by the, by the time I finish presentation, of an LADWP
could be sold on our project. Anyway, I go straight into this
presentation. What we are trying to do is actually transforming
fossil fuels to renewable energy. It sounds pretty simple.
Jamie Ormand: Just let me know when you want
to do it. It's not sure how to make it work.
Keen: Oh, okay. I think hydrogen is very, very been misunderstood. Hydrogen
does not, it's not found in natural
environment as a gas, it exists only as a
compound. So when we handle hydrogen, we have to produce the hydrogen package,
contain, transport, and store the hydrogen.
Currently, the matters to do it is
basically either liquifiy it or put it in compressed gas. I think we might be
able to change that. Our company is
actually a technology company that actually
the developed the first solid hydrogen carrier. Okay, and what we want to do
is to supercharge the renewable energy. What we want to do is actually produce
Keen: solid hydrogen in the form of sodium borohydrate, lithium
borohydrate, aluminium, and we want to have the entire chain to move over
to solid, so that we can ship them, store them at ambient temperature,
without any pressure so that we can transport them and safely produce
the hydrogen gas whenever you need. So hydrogen gas is actually using a ?
????? solution will be produced at the point of use. Transportation
of hydrogen is now solid. Solid material to be transported. Stored
without temperature control, without pressure. Now, the actual cause of
Keen: hydrogen logistic is actually very
different from what people think. First
of all, to produce hydrogen is actually pretty costly. The cheapest way is to
break natural gas or coal. But that will
be a brown hydrogen and not green. So what
I want to do is actually produce hydrogen
with renewable energy. Which the price
of the renewable energy has dropped,
drastically from, I should I say, 38 cents
down to two cents right now? Now, if we can
do that, then we would be ever to store
the hydrogen and transport the hydrogen as
a solid material. Because when you look
at liquid or gas hydrogen, you'll find that the production cost is very high.
Keen: The storage cost is very, very high. Transportation
is high, and the safety and containment cost is also
high. The upfront K Pax is high, and the end user cause is
also very, very high. Now, if you transferred that stage
to a solid, it becomes, production costs is still very
high. But storage, transportation, safety and upfront K
pax becomes rather simple because you're dealing with
solid and without pressure. And also without temperature.
Keen: Now, once you can do that, suddenly the
reach of renewable energy is not limited to
wherever you can disappear from the grid.
Hydrogen can be used for refueling station for
mobility in trucks, bus, train. I think train
and ship is going to be a huge market instead
of just car. ???? leaves UAV. I started off
this program because I was involved in the UAV
project in Taiwan. It doesn't work, it's too
heavy then. 10 years ago. Now emergency power
can be produced and basically hydrogen produced
on demand. Remote electrification, renewable
energy can, we can use every ounce of wasted
renewable energy and turn it into hydrogen,
solid hydrogen. And it can be exported, just
like oy, just like any hydrocarbon, it can
be transported. There's no restriction. Now,
there is a very big push in Asia on mixed gas
which is HCNG. Now, I am just wondering if
California is actually going towards HCNG, because
by giving, by mixing 20% in volume, we have a
clean gas. But that is really 3% in weight.
The 20% in volume is actually equal into 3%
of it. Safety. Storage and practically. What
we have done is actually created a hydrogen
generator that combine any NEBH4 with is a solid
material, water, and a waste system, so that
you can actually receive all the waste. The
reactor actually will take a solid material and
inject water and catalyst so that hydrogen
can be produced. Put in a buffer tank and
hydrogen can be supplied anytime that you want.
Keen: This is actually a very simple contraption
that can be produced by anybody in the
world. Now hydrolysis, which is what we're
using, is really an idea that has been used for
more than 100 years. Instead, off breaking
hydrogen free from water, which is electrolysis,
we are actually breaking water and the hydrogen
in the compound, freed by hydrolysis, is
completely self-generating. I technically do not
need to put energy when I split the hydrogen
from chemical and water. Now, the overall
system of, it's very high because the storage
of NEBH4 which is solid, you can store it in
normal temperature, without pressure, not
flammable. The logistics can be handled by any
assisting transportation infrastructure. No
cost because the energy could be stored. No need
for special equipment, only what they prove
it. NEBH4 can be used as any ????? at any
location. We place the reactor regardless of
whether there is electricity or not. Now the
generation of the electricity by the renewable
no longer is restricted by location. We put
the windmill at the point where the wind is
strongest, just like we drilling for oil in the
furthest pit. Maximize the production. Safety.
Really, there is very little you can do with
hydrogen. The only way that you can actually
mitigate safety is to minimize of volume and
pressure of hydrogen that you're storing.
Because if you can do that, you reduce the
chance of an accident. The two kinds of hydrogen
Keen: storage is very, I would say, ????? not
understood. The reactor that we create can
be mount or moved into any location. Okay? Low
cost cecause the cost of the neighborhood
will not be, should I say ????? discounted.
Once you put the hydrogen in the solid form,
long term storage is very, very simple and
cheap. Large quantity of fuel stores can
be storewith very, very little additional
expenses. Now this is the logistics of the last
mile solution. Safety on gas and liquid is
going to be difficult. But when once you're
moving over to a solid, it will be pretty
much manageable. Upfront K pAx is going to be
high. But when you are using a solid hydrogen,
the offering K PAX will be much lower.
Keen: Flexibility. Well, since it's a solid
material, you can technically move it any place
that you want. Operation cost is going to be low.
The reason is because it is a solid material.
Keen: The reason why I came back to California, actually, I'm from Malaysia.
I mean, some 40 years ago, I actually went back to Asia to develop this
Keen: project. Now the reason why I came back
to California, actually, California have done a
great job. This is probably the most robust hydrogen
economy in the book. A lot of people probably
never know it because we have the largest
infrastructure right now in the world for renewable
hydrogen. We also have the loan was cost in renewable
energy. Generated of course, right now, mostly
Keen: cartel. We have the ability to go right into an
HCNG mixed gas, which I think a lots of people is beginning
to understand. As China and India is moving forward on
it, we actually can expand the covering infrastructure
that we're providing for hydrogen. Hydrogen station can
be put into any gas station. Our unit that released
the hydrogen is actually very, very small, much smaller
than what other people are thinking. Now we can
supplement the assisting hydrogen infrastructure and
fasttrack California right into the adoptation of green
energy. We can also be a net hydrogen exportor because we
can export the hydrogen that we capture from renewable
and technically exported to any states that we went within
the United States. Go actually beyond that, California
can actually export a solid ecosystem and fast track
the growth of the whole world's renewable energy.
Keen: This is really what we are. We have, actually, there's
not very, very few people knows about our development until the
22nd off last month. Because that was the day that we actually
have a program from PCT for our worldwide patterns. So we are a
now found patterns throughout China, United States, California,
the whole, I mean, South America, Japan, Russia and Korea. We
have a very small company. We need help. We need help to spread
the fact that solid hydrogen can be done. Thank you very much.
Jamie Ormand: Thank you, Keen. All right,
Tom, you jumped up for questions. Questions.
Tom Henz: that's, you have an exothermic
reaction when you re-release for the hydrogen.
What is your solvent or what? What are you doing
to release the hydrogen back in the reactor?
Keen: Well, actually, I've been ????? to reduce
Tom Henz: Do you use like alcohol or?
Keen: In fact, I mean, I simply use heat and a catalyst
Tom Henz: but that's gonna be an exothermic reaction. So
how do you manage that heat generation with the hydrogen?
Keen: We actually have been process the release
of hydrogen by measuring the amount of water and
catalyst that is required, so that I can actually
extend the duration of the heat. I manage the heat.
Tom Henz: Okay, so you keep, you keep the thermal load and heat
below what would eventually could cause a fire or explosion.
Keen: No, in fact, I mean, we keep it below 90 degrees, because
that is really the optimum efficiency for production. Yeah.
Tom Henz: Thank you.
Jamie Ormand: Thank you. Alright. This is it.
Final rounds of questions. Thank you, Keen.
Keen: Thank you very much.
Jamie Ormand: Thank you very much. Okay. So
according to the agenda, which we are absolutely
on schedule for, we have made it through the
question and answer, the presentations,
and the question and answers. There is a
section on the agenda for Q&A on other topics
that we haven't touched on yet, so to review,
so far, we have touched on the renewable
natural gas interconnection tariff, the draft
that was submitted by the Joint Utilities
on November 1st. We have touched on all of
the 7 presentations that we have heard this
afternoon. Yes, the slides will be available
on the Web site in the next couple of days.
They only uploaded at the CPUC Renewable Natural
Gas website. So anybody who wants them just
give me, like, at least 24 hours so I could
get them to our IT to get them uploaded. We
have touched on the next procedural steps for
comments and reply comments both on the draft
renewable gas interconnection tariff and the
proposed decision on the reservation system.
Before we conclude, I do want to ask Jamie
one question, which is for your renewable
natural gas interconnection tariff on the
page 31, the last section, there's some error
reference source not found. Not a big deal.
It probably doesn't mean anything, but I was
just curious. Is there anything missing from
the number four and five that we, or four and
six in Section N, dispute resolution, that we
should know about? Please. The microphone.
Jamie Randolph: I believe what that is was we were referencing
a particular section, and there was, like, a hyperlink
in there when it got converted to pdf, it just created an
error. I didn't even notice that until you just pointed out.
Jamie Ormand: Okay, so we're gonna go with no big deal.
And if it is a big deal, maybe, in your comments, you
could just note with that what you mean for that to be
so that we all have that information, if you please. I
think we went through all of the questions that came up
during both sections. Are there additional questions
that I may or may not be able to answer at this time,
either on what we've touched on so far or any other topic?
Jamie Ormand: Oh, that was easy. So we've
heard a lot of great comments today.
Workshop comments spoken out loud at the
Commission are great to socialize information,
get people talking. In order to influence
Commission proceeding, we are a
quasi-legislative agency, which means you
have to write them down and submit them
as comments into the proceeding. The people who get to submit comments into
proceeding are called parties. Parties are
interested persons or entities that have
special obligations and rights at the Commission. If you have yet to file to
become a party and you want to provide
comments, please file to become a party and
provide comments. If you are already a party, we appreciate you taking the time
to write down your comments and then filing
them. And if you have questions about
how to do either of those things, my name
is Jaime Ormand and my information is
on the CPUC Renewable Natural Gas website.
All you gotta do is go to Google and
Google CPUC Renewable Natural Gas and all
my information is there, and since I
haven't seen anyone get up to look like
they want to ask more questions, I am just
going to say thank you very much for coming
and attending this afternoon. We look
forward to working with you and we'll see you next time. Thank you very much.