Sean Esterly: Good morning, or good afternoon, wherever you may be joining us from, and welcome to the third webinar of the 2016 Department of Energy Tribal Renewable Energy Webinar Series. This one is titled Transmission and Grid Basics for Tribal Economic and Energy Development. My name is Sean Esterly, today's webinar chair, and I'm joining you for the national renewable energy lab in Golden, Colorado. And just want to go over some of the event details for you today. Today's webinar is being recorded and will be made available on Western's website along with copies of today's Power Point presentations in about one week from today's broadcasts. And everyone will also receive a post-webinar e-mail with a link to the page where the slides and recording can be located.

And because we're recording this webinar, all the phones have been muted, but if you'd like to submit a question at any time, and we do encourage you to do that, just click on the question button located in the webinar control box on your screen and type your question in there. We'll be answering your questions at the end of the presentations today. And if you've entered an audio PIN when you join, at the end of the webinar, you can also raise your hand by clicking on the raise your hand icon, and I can go ahead and unmute you one at a time so you can ask your question directly to the panel.

We will also try to keep the webinar to no more than 90 minutes. We may go over in the event we have a lot of questions to address, and we do have several speakers on the webinar today, so let's go ahead and get started. Like to give a brief overview. So this webinar series is sponsored by two US Department of Energy Organizations, the Office of Indian Energy, Policy, and Programs and the Western Area Power Administration. The series is designed to promote tribal energy sufficiency and to foster economic development and employment on tribal lands using renewable energy and energy efficiency technologies.

So the office of Indian Energy, Policy, and Programs directs, fosters, coordinates, and implements energy planning, education, management, and programs and assists tribes with energy development, capacity building, energy infrastructure, energy costs, and electrification of Indian lands and homes. And so to provide this assistance, we work with the Department of Energy across government agencies and with Indian tribes and organizations to promote Indian energy policies and initiatives and to help tribes overcome the barriers to more energy independence.

To help tribes overcome those barriers, the Office of Indian Energy has developed several programmatic initiatives and partnerships, and this tribal renewable energy webinar series is an example of the type of education and capacity building efforts that we've developed with other Department of Energy partners. So after today, we have another eight webinars remaining in the series that we welcome you to join us for. Each webinar builds upon a foundation set and added to in the previous webinars. The foundation is strategic energy planning, and the often under valued or overlooked benefits of economic development and strategic planning process.

And in each of the 2016 monthly webinars, we will try to include tribal case studies and information and hands on tools that you can use to progress towards self-determination in energy independence. So now I'd like to go ahead and move on to some introductions for today's speakers. As I mentioned, I'm Sean Esterly from the National Renewable Energy Laboratory, and we do have an exciting agenda for you today and are very grateful to be joined by Kurt Daniel, Dave Narang, Jon Steward, Tawnie Knight, Scott Clow, and Bob Easton.

And I'd just like to go through and do a little introduction for each speaker joining us today. First speaker, Kurt Daniel, is electrical and electronic career. Includes stints as an aviation technician in the US navy, Boeing, Pugett Power in the city of Tacoma. At Pugett Power in the city, he maintained the metered standards laboratory, performed inter-timed meter testing in large power customer metering, served as a system operator and obtained North American electric reliability corporation certification at the reliability coordinator level.

Kurt then went to work for the Western Electricity Coordinating Council as a reliability coordinator, and then he as hired as an instructor at Western's Electrical Power Training Center. Our second speaker today is David Narang, who is a principle engineer in the power system's engineering center at the National Renewable Energy Laboratory, and a primary work focus area for David is to support the development and adoption of interconnection and interoperability standards for distributed energy systems. Prior to joining NREL in June of 2015, David worked as a senior engineer at Arizona Public Service in their transmission and distribution engineering technology assessment group.

His role was to facilitate the integration of renewable energy into the company's power generation portfolio. And at APS, he led projects to expand the company's knowledge and ability to manage the characteristics, performance, and reliability of photovoltaic systems and collaborated with internal and external business units to identify, develop, and coordinate technology research and deployment efforts.

And David holds a bachelor of science in electronics engineering technology from DeVry Institute of Technology, Phoenix, Arizona. Our third speaker today is going to be Jon Steward, and he is the transmission business unit manager in the transmission services department for the Rocky Mountain regions. Jon has been a member of Western's Transmission Business Unit for the past ten years, and he has been working with interconnection transmission service requests for the past eight years. Jon was also a member of a western wide team that modified its tariffs to be _____ order 890 compliant. He also served as a lead for implementing the changes western wide. In addition, he is also the vice chair of the West Connect pricing committee.   

 And providing our tribal case studies, we have two speakers joining us. The first is going to be Tawnie Knight, who is a member of the Ute Mountain Ute Tribe. She graduated from Fort Louis College in 2012 with her bachelor's degree in business management. Her title is the economic development specialists under the economic development division, and she enjoys her work with renewable energy. And Scott Clow is the second tribal speaker and is the environmental programs director for the Ute Mountain Tribe of Colorado, New Mexico, and Utah. Mr. Clow earned a bachelor's degree in chemistry and environmental science at Lafayette College in Eastern Pennsylvania in 1992.

And he started his professional career in analytical chemistry for Alpha Analytical Labs and then water test in corporate. He then went to work as a water quality specialist with the Ute Mount Ute Tribe in 1996 assisting the tribe in monitoring – in assessment and eventually in obtaining delegative authority for water quality standards. In 2008, he became the director for the environmental programs department where he works today, and he represents the tribe on the regional tribal operations committee, and he represents the tribes in Colorado, Utah, and Wyoming on the national tribal caucus. Currently he is the Ergo lead for the NTC and Scott is a recipient of two Friend of EPA Awards and a Frank Dakota Award from EPA and a Natural Resource Division Award from the tribe.

 And then our final speaker today is Bob Easton, who has been the vice president of transmissions services for the Colorado River Storage Project, Desert Southwest, and Rocky Mountain Regions of the Western Area Power Administration since 2014. His responsibilities include all aspects of transmission planning and transmission services for Western System and Southern Montana, the panhandle of Nebraska, Wyoming, Colorado, Northeastern Utah, and Arizona. Bob joined Western in 1983 and has held positions in construction inspection in the Dakotas and Eastern Montana, transmission planning engineer in Golden, Colorado, scheduling and billing manager in Phoenix, Arizona, and manager of transmission planning North Rocky Mountain Regional Office, located in Loveland, Colorado.

And Bob has a degree in electrical and electronics engineering from North Dakota State University. And so with those introductions, I'd like to go ahead and welcome our first speaker today, Mr. Kurt Daniel.

Kurt Daniel: And can you hear me?

Sean Esterly: Yes, we can Kurt.

Kurt Daniel: Very good. Good morning and good afternoon, whatever the case may be. My presentation today, I'm going to be talking about Western Area Power Administration's region and facilities overview, and actually, I'm going to skip those first two slides because that's information that's available on our Western website. We'll also be talking about the fundamentals of electricity power transformers and transmission lines, and we'll discuss kind of a brief overview of the bugged electric system. We wanted to go to Slide 5, what we have is the magnets. What magnets do is generate magnetic field around the magnet. We can take that magnetic field of that magnet and can pass it through, in this instance, a tube that's wrapped with some conductor wrapped around it, and we're actually breaking that magnetic field with those lines of flux from the magnet. Am I still on?

Sean Esterly: Yes, you are.

Kurt Daniel: Okay, just went silent there. When that magnetic field is interrupted by those wires, then a current is created. And we want to go to our next slide, and I can kind of explain what current and voltage are. Voltage would be analogous, and we use the water analogy quite often in the electrical power field. If I have a reservoir or container with water in it and a pipe or tube, which would actually simulate a pin stock for a hydroelectric generator, if I don't have an opening to let that water go through, I'd develop a pressure, and that would be analogous to voltage.

If I were to open that valve, I'd then have a flow through the pipe or the tube or pin stock, so that would be analogous to the current flow. I'd still have the pressure or the difference potential, but now I would have voltage and current. What does that do for us? We want to take that power. This would be something that we develop say in a hydroelectric generator. I have current and voltage now, but it's no good to me unless I can get it out into the system where I'm going to use it. On my next slide, we'll talk about transformers, and all – basically all they are is two or more coils of wire wrapped around an iron core. It's really a variation of an inductor, which is a magnetic field device. In this sentence, I'd put power on the primary side. I would then do induction, develop a voltage and current flow on my secondary slide.

We'll go to our next slide. In this instance, if I were at my generator or whatever the prime mover would be, I'd be taking my lower voltage, which in this case is 11.5 KV, and a higher voltage which is 870 amps. This transformer is a ten-to-one transformer. I'd be stepping my voltage up from 115 KV – I'm sorry, from 11.5 KV to 115 KV. Inversely proportional would be my current, which would go from 870 amps to 87 amps. Same thing, it's the inverse proportional, ten-to-one ratio. My next slide, I would be taking this power out to my substation. In that substation, I would have this transformer arrive. I have transformed my voltage level. I could be going to a circuit breaker, which is – would isolate faults from the rest of the system, or if I wanted to energize the line, I could close that breaker and energize the line.

I'd also have disconnect switches, which would allow me to operate in a de-energized state to isolate equipment for maintenance repair. I might have lightning protection, lightning _____ in there. More importantly, I'd have instrumentation like potential transformers, current transformers to give information to my relays for line protection. I might also have transformer protection, like differentials or sudden pressure relays. And my next slide here is a depiction of a complete system really. I'd have my generation station, which regardless of prime mover, I'd be developing current and voltage, which would then go to a transformer and would step up that voltage and step down that current to go onto my transmission lines.

 

                                    I would transmit that power to another substation where I might step that down, and serve end-use customers, maybe a sub-transmission customer. So maybe a customer that's primary on the line up the high voltage, or to a secondary customer that's like a resident that's going to use a 120/240 volt system. Since we are hydro on the next page, just kind of a quick shot of what hydro's generation system looks like. To the left, I'd have a reservoir with my trash rack. My pin stock, which would allow water to flow in through wicket gates into my turbine, causing my turbine to turn. I'd excite that rotor and develop power coming out of it, same thing.

 

                                    I would take then – step up that voltage, step down that current, put it out on my transmission line, and then serve a load, which is my light bulb. As far as the transmission system on the next slide, it could be of many different voltage levels. In some systems, they may call the transmission voltages say 230 KV to 765. We might call the sub-transmission system 69 KV to maybe 138 KV. And what does that mean? On our next slide, we would see a depiction of a transmission system versus a distribution system. Basically, the higher the voltage, the more clearance will be needed between the phases and ground.

 

                                    So the higher the voltage, the larger physically those structures have to be. The larger physically it has to be, the more expensive it's going to be. We can go to our next slide, and we can actually show a depiction of our size ratio. For instance, to the left, I have a 500 KV transmission structure. All the way to the right, I have maybe a 13 or 12.5 KV distribution structure. You can see that, and the difference in size, obviously the cost and materials are going to be less for distribution.

 

                                    On our next slide, we can talk about our thermal ratings of our transmission lines. Typically, transmission line – and as a reliability coordinator, what we like to see is more than one rating for a line. We can have a maximum continuous rating on the line. I can carry this amount of usually MBA or megavolt amp here forever. I could have then maybe a higher emergency rating, say I could have a higher four-hour rating or maybe a real emergency 15-minute rating. And again, those ratings are thermal ratings. They will be affected by ambient temperature. If it's a very hot day, I won't be able to load that line as heavily as if it were a cooler day, and maybe with some wind to wick off some of that heat.

 

                                    On my next slide, I can kind of explain why we're concerned about heat. We have something called sag, and on my – this is true of all lines, whether it's distribution or transmission. On a cold day, I would have less sag on my line because the line won't be as hot. It won't expand as much. On a full load day or a heavy load day when it's hot, I'd have a lot more sag, and I could sag into trees or I could sag into my under build or a lower voltage line. And on my next slide – so how do we measure electricity?

 

                                    We usually measure in terms of watts, so 1,000 watts would be a kilowatt. A thousand kilowatts would be a megawatt. One way to think of it is one megawatt, I could instantaneously light maybe 750 to 1,000 homes. A kilowatt or megawatt when we use that energy, it's got to be actually used at the same time it's generated. So that's the thing about our industry. We produce as needed. I turn the light on, light comes on, I need that power immediately. It's an instantaneous type demand situation. Next slide. How do we measure this?

 

                                    So for billing purposes, for instance, in a residence, we're going to measure you're usage over an hour in something called a kilowatt or a kilowatt-hour. That's what our billing quantity would be for low-end users. For bulk electricity or large transmission quantities, we would typically do that in megawatts or megawatt hours at the wholesale level. Next slide, again, it's an instantaneous demand. As soon as load demands power, we have to deliver that power from our system.

 

                                    As far as storage, it's really something that can't be stored, although there have been some innovations, especially in the renewable energy field. For instance, if it's late at night, I have really low loads. What'll happen is the system voltage will rise, and the system might actually speed up. I might have the over generating, maybe I have some must run units. I can't back them up any further. I backed up all my conventional generation, and a practice that's becoming popular is to install what they call pump storage units. So at night when my loads are low, my voltage is high, maybe my system is running faster due to over-generation, I can energize some of these pump storage plants. I can then refill my pond, and then when system load starts to pick up and we have peaking, I can then use that stored energy.

 

                                    I've just converted the wind power to another form of prime mover to hydro. I can then take that pump storage and use that for generation. So that's another way of storing renewables. Next slide. The real issue is in the bulk electric system is to balance generation or resource and load demand, and that's typically going to be done by automatic generation control systems and balancing authority. We'll talk about it in a few minutes here. But kind of let's talk about the next slide. Let's talk about our generation mix. And with the advent of interest in carbon footprint and damage to the environment, we're kind of moving away from coal as a prime mover source and moving more towards natural gas. The natural gas is a benefit we realized from the new technology for oil fracking. We get a lot of natural gas off of that. So we're using that natural gas, and that now is becoming more of a prime mover source, so that has some issues with the fuel delivery pipelines, fuel storage and stuff like that.

 

                                    What NERC is saying now, if I install a new – typically it's going to be a combustion turbine or combined cycle generator, I'll have to make that unit a dual source fuel. So natural gas and perhaps petroleum. We can go to the next slide. In the west, this is kind of a representation or actually facts of what our generation resources or prime movers look like in the western interconnection. On the left there, you'll see that coal is down to about 27 percent, natural gas is up to about 30 percent, and these are estimates. Our hydro is pretty – the mature industry, so we're not building a lot of new hydro, other than pump storage, but at that, we're looking at about a 20 percent penetration of hydro. Of note, you can look at some of our penetration of renewables, so we look at our wind is up to about seven percent, solar is up to about two percent, and again, the natural gas- the reason for the increase in natural gas is largely due to the oil fracking technologies.

 

                                    We can go onto the next slide, and in North America, there are four interconnected grids, and what that means is that we have four areas within North America that are synchronously connected internally. We have the west, which is us, we have the east, we have the great sovereign state of Texas, which is Ercon, and we have hydro Quebec. And there are – even though these interconnections are not synchronously tied via AC, they will have high voltage back-to-back DC line, and we will do a lot of energy transfer across those lines.

 

                                    Typically you'll see from the western interconnection to the eastern interconnection, or from hydro Quebec south down into the northeastern part of the United States. We can go to our next slide. And we look at seasonal variations for our bulk electric system. We have – oh. Let me see, I'm missing a slide. I'm sorry, we're looking at daily power flow on the bulk electric system. For instance, early in the morning, we're going to have light loading. Voltages might rise. Our system might speed up because we don't have the load to slow the system down, so we have a higher frequency. As load picks up, an interesting thing dispatchers do is they want to get under the voltage as the system load picks up. We have a factor called a per unit voltage, which all of our reactive voltage control devices like shunt capacitors and shunt reactors are very limited by per unit voltage squared actually. I have a 100 KV system, I have a ten-mega bar react advice of whether it's inductive or capacitive. I would only get the per unit voltage squared value out of that.

 

                                    So my voltage is down to a .9 per unit or nine-tenths of what the rated value is. I can only get eight mega bars out of that ten mega bar reactive voltage control device. As you'll notice here, too, we might have an early morning peak and maybe an evening peak also. And then as people go to bed and business shut down, we'll go back to that low load, high voltage, high current type of situation. We can look at the next slide. Our power flow and our bulk electric system is actually seasonal in nature, too. Perhaps in California in the summer, at- in the late afternoon, you'd have a lot of air conditioning load because it's hot out, or for instance, maybe in the east, your peaking might be in the morning where you have – it's cold and all the heat sources are coming on.

 

                                    So it's going to vary from season to season throughout the bulk electric system. Also, there's something called load diversity. If I have a long outage, regardless of whether it's hot or cold out, everything that is in my residence or business is going to demand power as soon as it's made available. Normally throughout your day, we have something called load diversity, so your refrigerator and your furnace and other motor loads are never on at the same time. We call it cold load pickup. I’m restoring my system, average – been de-energized for a while, so all that equipment will come out in the same time and demand energy. We call that cold load pickup, and we get 10 to 30 times what our daily – our average load may be.

 

                                    We can go to the next slide. This is kind of a diagram of what our daily demand curve or what our generation mix. I might have units that are base loads. For instance, coal or nuclear power that don't change their megawatt output very easily. They don't like to move. I might bring those units on for a base load to serve a certain portion of my load profile. I would have some units that are easily moved, like hydro or combustion turbines to maybe follow my load.

 

                                    And I might have another generation resource like again, combustion turbines are really good at this for peaking or you could use hydros via pump storage to get those high peaks when you need them. We go into our next slide. We have in our industry, we have energy which is megawatts, or we have capacity, which would be a thermal limit on the line. We also have two kinds of power resource. We have a dispatchable resource, which is more of conventional generation, which would be hydroelectric or natural gas, fire, combustion turbines, or base loaded energy sources like coal or nuclear power.

 

                                    In our industry now, we're having more and more penetration of non-dispatchable type of energy resources. Typically wind and PV or solar. Some issues with some of those. It's getting better, but for instance, they have variability that – uncertainty are part of those. We may not be able to forecast very well right now, though the technology has improved a lot and it's getting better all the time about when our wind might be available to give us some output. Of course we know that at night there's no sun, so there again, we're looking at a way to maybe store that energy. Again, so those resources, those non-dispatched resources really had to be used when they're available.

 

                                    And next slide is kind of an overall view of the interconnected system. We would have our transmission line with our different prime movers. From a right to left, we would have our dispatchable gas, coal, nuclear. Those again might be base loaded. They're more of a thermal type of generation. In the center, we'd have our hydroelectric, again, including our pump storage, which are becoming very popular. One of the good factors about pump storage is typically you may not have to meet any FERC guidelines as far as stream flows or if it's an artificial pond. No problems with fish or things like that, so that's another attractive thing about pump storage.

 

                                    Also have things like biomass and geothermal, and then our non-dispatchables. All the way to the left, we're going to have our wind and our PV, which again are renewable resources. We can go to our next slide. Well how do we regulate this? We have FERC, who is the federal energy regulatory commission, and they regulate the transmission of wholesale- really all energy that goes across state lines. So natural gas, electricity. They also are going to monitor the energy markets to make sure that another Enron type thing doesn't happen. We have NERC, the North American Electric Reliability Corporation.

 

                                    And NERC establishes reliability standards that grid operators must adhere to. FERC actually oversees a lot of what NERC does. For instance, FERC might find someone in violation there that didn't adhere to a standard and sanction them with a fine. Well FERC actually has the final say-so as to whether that fine is appropriate or maybe too much, maybe not enough. Good thing about being fined by NERC is they're going to make you fix whatever it was that made you not adhere to that standard. So for instance, if I have a $10 million fine, they might say, "Okay, we're going to give you $8 million of that to correct whatever it was that – to mitigate whatever it was that caused you to violate that standard. Then we have our RROs, or our regional reliability organizations, which are an arm of NERC, and they do periodic audits and – of the grid operators and levy fines for non-compliance.

 

                                    On our next page, next slide, we show some of those RROs. There's WECC, the MRO, Ercott in Texas or TRE. One thing that these RROs can do is they have standards that are set by NERC, and you can actually make those standards more stringent for a region, but you cannot make them less stringent. And we can go to our next slide. So who regulates our internal electrical industry? We have utility commissions, so we might have a PUC or a public utility commission, public service commission might oversee some bodies other than the utility regulator, or we might have a public utility district that might deal with the tribal entities, states, and government owned utilities.

                                   

                                    What these PUCs or public utilities will do also is determine the rate of return you can recover if you build, for instance, the new transmission line or install a new generation facility. You want to get paid back for that. Your customer is going to be the one that pays you back. Well how much and how fast can you recover that from them? We also saw something called on the next slide – we have regional transmission organizations in the United States. For instance, the Cal ISO. We have MISO in the Midwest, PJM. Those are going to be our regional transmission organizations. We can go to our next slide.

 

                                    This is really kind of the workhorse of the bulk electric system is over 100 balancing authorities in the United States, and what their responsibility to do is to balance resources which could include their internal generation, or interchange that they buy via schedules over their timeline. They take and balance that resource in real time against the load demand within their footprint, and the key, the purpose of this is to support our interconnection frequency in real time. As I mentioned, electricity happens now. So as loads come on, a big load can cause your voltage to go down, it can cause your frequency to dip.

 

                                    If I were to lose a big generator or something, I could cause a frequency excursion, and I'd have to recover from that. We can go to our next slide, and this kind of lays out a little bit about why reliability entities, in particular balancing authorities, deal with something called reserves. If you look to the right of the diagram, it's basically what is the total generating capacity or capability of your balancing authority. We'd have a certain amount of generation or resource that would be dedicated to serving firm load.

                                   

                                    We would then have – and we'd have another amount of online generation, this is going to be online synchronized to AGC, which is automatic generation control, which is the tool dispatch uses to control the output of our generators. We would have a portion of that generation capability that's online synchronized to AGC that would be required for following load, and we'd call that regulating reserve. As loads come on and off, we're going to pulse up or pulse down our generators to reduce output.

 

                                    We'd also have a component of reserves called contingency reserves. For instance, if I have a 1,000-megawatt generator and I lose 80 percent of that or 800 megawatts, we would call that simply what we called our MSSC, or most severe single contingency. I might cause a frequency excursion, I might drive my ADC output, which would be my area control error down. I'd have to, per NERC, recover to my pre-disturbance state within 15 minutes. That would be the purpose of having contingency reserves. Right now, NERC says you look to the left of the diagram, we have operating reserves. At this point, NERC says that 50 percent of your contingency reserve must be spending reserve that's online synched to AGC ready to serve immediate demand.

 

                                    We have another component of operating reserve called non-spin or non-spinning reserve or supplemental. And that would be generation that I can start and load to full capacity within ten minutes to recover from a contingency. It could also be customer load that I've made a contract with a load to interrupt that load. We call it interruptable load. A flick of a switch, I can right away shed load, and that's what the dispatcher's authorization letter says, that you can take any action up to and including the shedding of firm load to preserve the reliability of the bulk electric system and to prevent cascading outages. We also have a new source called ready reserve. I have a generator that is not generating megawatts, but I'm using it for voltage control to – as a synchronous condenser to over excite and produce more bars and raise voltage or under excite to absorb bars on lower voltage. We can really quickly turn that back into a generator and use that as what they call a ready reserve resource. Our resources here, we look at our next slide. This information was garnered from NERC, from the electricity supply and demand database, and the Office of Indian Energy, and NREL, from their renewable energy data book, and also the DOE Office of Electricity and Transmission as a primer. Very good resources.

 

                                    So what do we talk about? We kind of skip the western area statistics, which is available on our website, and we talked about our fundamentals of electricity and did a kind of brief overview of the bulk electric system of the grid. And that completes my presentation.

 

Sean Esterly:              Great, thank you, Kurt. We're going to move ahead now and turn things over to David Narang for his presentation.

 

David Narang:            Okay, getting to it. All right, can you guy see my screen and hear me all right?

 

Sean Esterly:              Yeah, you're good to go, David.

 

David Narang:            Fantastic. Good afternoon, folks, to you all and thanks for tuning into this webinar. It's a real privilege to speak with you today, and I'm grateful to Sean, Guy, and Randy for a chance to present. I've got about 20 minutes to share some information, which I hope you will find useful. Here is a look at our agenda. There's basically two parts to this talk. Part 1 includes a quick overview of distribution systems, electric utility operations on the distribution side. Some emerging topics in grid integration and the Department of Energy's plan for accelerating efforts for grid modernization. Then in Part 2, we're going to switch gears to review permitting and interconnections, and then I'll just wrap up by giving you some additional resources if you want more information for later.

 

                                    So as some background, I just wanted to review that NREL is one of 17 national laboratories owned by the Department of Energy. The DOE labs have four mission areas as you see listed here on the top, and those areas are nuclear security, science, energy, and environmental management. And a big part of the purposes of the DEO labs are to solve important problems in each of these mentioned areas. Also to maintain vital scientific and engineering capabilities at our facilities and to promote innovation that advances US economic competitiveness. The graphic in the middle shows our intended role, which is to exist in cooperation with the university community and industry, and to really help scale up the basic science carried out to universities. So those ideas can be adopted by industry. Our teams and facilities at the DOE labs are really ideally suited to support large complex multidisciplinary long-term projects.

 

                                    But we enter into more tactical projects as we see the need arise. On the bottom right, you see the location of the labs, and I'm speaking to you from the NREL facilities in Golden, Colorado. NREL is unique among the 17 labs and is focused on commercializing and deploying energy efficiency and renewable energy technologies. The lab bridges science and markets by working closely with private industry and with federal state and local agencies to bring really competitive products to market and to deploy them in significant scale. On this slide, I've highlighted the systems integration group, to which I belong, and this team works on the topics you see listed, including grid integration of distributed energy systems, building energy efficiency and control, cyber security, and distributed energy standards.

 

                                    This slide really takes off from where Kurt left us, and is intended to give you a high-level overview of a typical distribution feeder. On the right is a graphic that shows some of the major equipment you'll find, including the substation transformers shown at the bottom right, which happens to be the head end of this feeder. So the term feeder refers to the wires and all the related equipment that carries electricity from the substation on the bottom all the way to the end of the feeder.

 

                                    So along the way, you'll find ground mounted and pole mounted distribution transformers that as Kurt mentioned convert the distribution or primary voltage into secondary or service voltage. We also have some voltage regulating equipment like capacitor banks and voltage regulators to maintain that voltage within ANC limits. You will of course find customer loads, residential, commercial, or industrial loads, and many utilities now have wireless digital meters that measure those loads.

 

                                    On this particular feeder, you also see both large scale and residential scale solar energy systems. So a utility's operational goals for this feeder would be to maintain clean, reliable, safe power that's within the load carrying capability of all equipment. And these goals would be carried out by the distribution operation and distribution engineering and planning departments primarily. In other groups within the utility, other issues will be managed, and you can see there's many other important considerations that go into making sure that utilities are managing risks and opportunities in a fast changing world. So some of these considerations will affect distribution operations and engineering and will also affect, therefore, interconnections and permitting.

 

                                    A lot of the previous issues depend on having good information from the field. And generally, utility process for understanding our electric system falls into two broad categories. We get situational awareness from things like our energy management system with near real-time loading feeders and related parameters. We have information about our feeder topology, shows how our feeder is laid out and what equipment is where from our GIS systems all under situational awareness. As I mentioned before, we have more information coming from automated metering infrastructure like digital meters and – we discussed earlier.

 

                                    We also have power system studies and tools used in planning and these studies and tools really fall into two parts. The steady state tools and studies that are the load and power flows, short circuit protection coordination, and the more dynamic studies that would be done for transmission connection systems for voltage stability, for example. As we know in the past five to ten years, there have been many new technologies and considerations that make it hard to get that field information. And there's a lot of discussion in all of these changes that are occurring that affect utility operations and electricity markets. I've highlighted just a few illustrations on the next couple slides to give you examples of how this is evolving. So as you know, a big deal is physical and cyber resiliency. As we see an increase in extreme weather events, super storms and such, and we see an increase in cyber attacks on electric infrastructure, our picture of how the grid is operating begins to degrade during those events.

 

                                    Other elements that degrade that awareness is our changing electric generation mix. As Kurt mentioned before, we have more and more variable generation that's coming online, and so a lot of this is the result of growth and distributed renewable energy. And we expect more as we try to meet new standards in clean energy goals. And as we anticipate prices for solar energy systems to continue to drop so it becomes more affordable for people, we'll see an increase in these types of resources coming online.

 

                                    So other emerging complexities really – there's I just put them in two buckets here. Customer side or prosumer participation. And technology innovation or grid interactive technology is more on the utility side. So under the customer side, you see of course energy efficiency measures like LEDs, possible energy storage systems coming online. I've noted here the smart thermostats really falling under the term of dispatchable loads, includes home or building energy management systems, and also includes plug-in hybrid electric vehicles on the consumer side.

 

                                    On the utilities side, landscape is changing a lot as well. We have things like conservation voltage reduction and integrated volvar controls being implemented on feeders. We have, as I mentioned, automated meter readers, reading infrastructure with expanded data sets with more sensors. We've got self-healing feeders. We've got things like smart inverters and micro-grids. All are designed to improve the capability of the distribution system to kind of meet all of those challenges in that previous slide.

 

                                    So as we noted earlier, the ways utilities have of understanding and managing distribution systems kind of degrade when you add all of these complexities, and we find there are a lot of gaps in that understanding. If we add all of these elements. In both the near and the long-term. So everything you see in red here are possible gaps  in our knowledge or our toolkit for managing these distribution systems. So when we think about it, it's not surprising to observe that if we start with more complete and timely information, the more accurate our predictive modeling will be. Kurt mentioned solar forecasting. And also this would include more detailed and accurate information about where the PV systems are in the first place, how they're oriented, what their size are, what the capabilities of their inverters are and so forth.

 

                                    And under power systems, studies, and tools, we have a whole new set of what we call advanced scenarios we think need to be performed at much faster time scales than have normally been done before. To address all of that variability and quasi-static behavior of clouds passing by and so on. So the Department of Energy has put forth a vision for this emerging power system, and really the main goal is a sustainable, affordable, secure and reliable electricity grid that can drive the clean energy economy.

 

                                    In an answer to some key questions, they've laid out goals in the areas of clean energy, reliability, and affordability. And the chief goals are ten percent reduction in economic cost of power outages, a 33 percent reduction in costs of reserved margins while still maintaining reliability, a 50 percent reduction in net integration costs for distributed energy resources. And the overall vision is to try and achieve these goals by 2025. So desire to move very quickly on some of these goals and topics, and to help achieve these goals, the Department of Energy recently launched the grid modernization lavatory consortium. And this is a strategic partnership between DOE headquarters and our national laboratories to bring together all the leading experts and resources in those complexes to collaborate on the goal of modernizing the nation's grid.

 

                                    If consortium uses an integrated approach to ensure the DOE funded studies and research and development efforts are efficiently coordinated to gain the greatest return for our taxpayer dollars. So this is a five-year grid modernization strategy that includes the alignment of existing base activities among the offices, and integrated multi-year program plan, new activities that fill the gaps in existing activities, and a development of a laboratory infrastructure with core scientific abilities and regional outreach. The DOE expects to spend up to $220 million over the next five years to conduct this type of research and to conduct demonstration projects in partnership with the national lab and private companies to help accelerate this effort.

 

                                    Key areas are listed below. These include sensing and measurements, devices and integrated systems, systems operations and power flow, design and planning tools, security and resiliency, and support for institutions to help implement some of these ideas locally and on a regional basis. That was the really overview of Part 1. We're going to switch now gears to get into the permitting and interconnections portion. All of the previous slides were really intended to inform you about the possible considerations you and your team members may have to address as part of your project development and interconnection processes.

 

                                    Permitting adds an impact on the whole project development lifecycle as you know, and we're going to look at that for the next few slides. The role, of course, that you choose for your participation on the project of course affects the level of direct effort required on permitting. And one needs to consider the opportunities and constraints that each role brings very carefully. Regardless of that role, every member of the overall team has a responsibility towards the successful and timely permitting. So highlighted folks on your potential team that will be especially involved in this permitting process here.

 

                                    This includes leadership staff, attorneys, engineers, working on procurements and all the permitting sub-tasks. So as we already stated, permitting will have an impact over the entire course of the project. Even in the project's potential kind of exploration assessment stage, the relative length for obtaining permits will be considered and weighed against other potential projects. This will affect your project strategy, who you hire as partners, and will definitely affect your planning and development in the implementation stages. And will also affect site operations in terms of compliance long after the project is constructed.

 

                                    So plainly, site location ownership and jurisdiction play a big role in determining permitting and project requirements and the scope of work for the team. For example, at a city level, I'm using an example from Tucson, Arizona. Permits may fall broadly into two categories. They may be environmental and building or construction. Under environmental, as you know, you'll have your storm water pollution prevention plans, ground water, surface management, aquifer protection and so forth. Under the building and construction permits, you'll have your zoning classifications, building permits, electrical permits, city flood plane permits, site development plan, and so forth.

 

                                    As you know, at the federal level, there are many more entities involved at local, county, state, and federal levels. And the issues will involve not only on environmental and building, but it will also include security or safety agencies like Department of Homeland Security or potentially coast guard, FAA, and any energy regulation such as fur, like Kurt mentioned. On these projects especially, I think the permitting team manager makes – needs to make sure to drive communication and process among the various entities to keep the project on track.

 

                                    Switching to interconnection agreements, which are described as the technical rules and procedures allowing customers to plug into the grid, these interconnections can happen at the transmission level, as Kurt mentioned, or at the distribution level. Now if that transmission one would also need a transmission service agreement that allows the generator to wheel power across lines of maybe somebody else's own. And if you're selling that power to someone else, you'll have to have a power ____.

 

                                    And these are very important agreements, not only for the seller, but will also affect utilities' generation stack and marketing and trading operations. At the distribution level, you know that utility has its own set of interconnection requirements. The interconnection application kicks off the formal process, but for a large projects as you know, there are likely more discussions for that. So the process includes the technical scoping piece, which includes a common understanding of the project, rules for operating and agreement on generator size, point of interconnection. It also includes technical studies designed to maintain safety, system stability, cost for upgrades, or new infrastructure estimates.

 

                                    So formally, these are the feasibility study, system impact study, facility study. All of these are done for transmission connect projects. For small generator interconnections for distributed connected generators, especially under two megawatts, you might have fast tracks. So integration, just to recap, integration interconnection issues related to renewables might be simple or minimal with no study, no impact, no mitigation required. You might have some study required that shows minimal impact requiring that a minimal amount of mitigation. For example, running a generator off of unity power factor, or you might have complex components, equipment and interactions requiring extensive study and corrective mitigation required.

 

                                    Kurt mentioned a list of entities that were especially interested in this energy interconnection and power flow, which included NERC and FERC. There's also other entities, of course, that are interested in addition to the utilities. As Kurt mentioned, state public utility commissions. But also Department of Energy, the Power Marketing Administrations. Certainly technology developers and vendors, and research community. We all need to align on the standards for how all of these technologies are implemented and how we work with each other. So here's a list of some of the important standards related to interconnection and interoperability along with a quick bullet on what these standards are focused on.

 

                                    I'm sure you will be familiar with these standards, especially the 1547 nitro police standards and the UL 1741 for distributed energy resource interconnection. And the National Electric Code that are usually baked into utility interconnection requirements. Also new interoperability standards coming out of IEEE 2030 and testing standards coming out of 1547.1 processes really helped define how other equipment operates. For example, micro-grid.

 

                                    All right, only one more slide to go. Additional resources that you can tap into, I've listed a few examples here. At the state level, you have the California Solar Permitting Guide Book. I especially like the resources at the International Finance Corporation. Check it out, it gives you a great blend of technical and overall information. Other resources are the Interstate Renewable Energy Council, BLM, DOE energy efficiency, and renewable energy website. Kurt mentioned a whole bunch of great resources. And I also wanted to mention three resources out of NREL. One is the Distributed Generation Interconnection Collaborative. It's a series of webinars that you can join to learn from other practitioners about distribution interconnection issues and solutions. There is a technical assistance for tribes that NREL offers through the Department of Energy Funding, and we've recently published a PV handbook related to high penetration for distribution engineers.

 

                                    So sources are listed at the bottom of my website presentation, and I wish you the best of luck in all your projects. That is the end of my presentation. Thank you very much.

 

Sean Esterly:              Thank you, David. And so we'll move ahead now to the next presenter, and that's going to be Jon Steward from Western, and Jon, I'll pass over the controls so you can show your presentation.

 

Jon Steward:               Okay, give me one second. Can everyone see my screen?

 

Sean Esterly:              Yes, we can. You're all set.

 

Jon Steward:               All right, great. Good day, everyone. My name is Jon Steward with the Western Area Power Administration, and I'm going to go over the interconnection process as well as some transmission service request processes. David started diving into it a little bit, so I'll go in a little bit more detail than the previous presentation. Some things I'll be covering today are the interconnection types, some of our old revisions we've made, as well as the transmission service issues that come up. Towards the end of the entire presentation, we'll have an open discussion or any questions you may have. Just to clarify, there are two types of processes we have here at Western. This is – what I'm going to go over, it's typically found in the majority of transmission service providers you may deal with.

 

                                    You usually have a large generation interconnection process and a small generation interconnection process. And the differential mark between the two is 20 megawatts. So 19.999 is considered a small generator. Twenty megawatts or above is considered large generator interconnection request. The last one – we also have what's called wires to wires request as well, which are usually used to serve additional load. Here is a very – it may be difficult to see, but as you can tell from all the boxes, to go through the large generation interconnection process, it does take some time. What we have experienced, at least from my own experience, if you're thinking about interconnecting to a utility, I'd say you may want to expect about 12 to 14 months for the technical state of work to get done.

 

                                    That goes from the feasibility study to the system impact study onto the facility study, and in a moment, I'll go in more detail what you'll get out of each of those studies. But typically, the technical work is usually the easier part of the interconnection process, and someone kind of alluded to the more lengthy process is really the environmental side or getting – obtaining those permits. Now Western as a federal agency, we do fall – NEPA, which is the National Environmental Protection Act, so there's some requirements we must do on the environmental side.

 

                                    I'll go into a little bit more detail as we go along for that one. Now Western is a little bit different, and then some other entities you may want to interconnect with. But quickly, we start the process for a large interconnection. We have an application fee of $10,000.00. However, in recent years, most utilities have changed that requirement, and now they differ between $10,000.00 to up to a quarter of a million dollars of deposits in advance. Someone may be asking why did they change it and make the requirements so high.

 

                                    Well when the renewable push came on or surge came on several years ago, a lot of requests were being made to the transmission service providers. Some of those requests were just tying up Q spots and preventing providers from looking to what some may consider the more serious or more advanced projects. So to determine if someone is very serious about their project, they raise up the requirements. These ones that are identified as deposits, they will be applied towards working on your project.

 

                                    Now one thing we do ask for, and it's not required, but it is preferred is to have side control. Some transmission providers may deal with we'll ask each to provide us. Now for the small generation interconnection process, it is required to have this. Here is three examples of what is side control. In essence, you must present to the transmission storage provider a document that states either you own the land, or you have a lease option, or permission from the landowner to build a generator on that site. Now I'm going super fast because I know we're kind of a little bit behind time. One of the studies that has been – that was kind of identified in David's presentation that he hit on, it was called a feasibility study.

 

                                    In essence, what this study is is if you were to submit a request to the transmission service provider, you're not quite sure of what the outcome is. Some people have chosen to go do this study. It is an optional study. It is not required. And the results of the study, you'll get an idea, in essence, more like a 10,000-foot view of what will happen to the interconnection system if your power plant were to connect to it. Going a little bit fast. But the next phase in the process is the system impact study. Now this study is required for all interconnection requests. This is for, in essence, where the rubber meets the road. A study will be presented to the customer. Once it's signed, provided to the transmission service provider, and deposit is made typically at $50,000 worth of study costs.

 

                                    The transmission service provider will begin analyzing your request. They will look at the impacts of your generator interconnecting to the system and identify if there are any medication items needed. Typically what they'll look at to see if there are any voltage problems or any thermal overloads, and then they will provide to the customer in a report if there are any overloads or any voltage problems and what the mitigation is to correct that problem.

 

                                    And in that report, it will say we analyze, for example, that there was overload on Line X. We'll re-determine that in order for you to mitigate that, you'll need to either (a) rebuild the line or build a new line, or make upgrades somewhere else on the system. They'll provide you a cost of those upgrades a ballpark cost as well as a very high-level schedule. In essence, they may say to build a new line, you're looking at $8 million, and we estimate for it to take six months or one year of construction time.

 

                                    Now once the system impact study is complete, the customer will now have the option to do a facility study. Excuse me, it is mandatory for them to do a facility study. Now sometimes a customer may look at the system impact that it results and determine the costs are too high. Not economical for me to build a new line and have its power plant connect to the system. Instead, I'm going to withdraw my request. But for those that want to forge ahead and continue on the process, the next step is the facility step. In the facility study, it's rendered that the transmission service provider will dive into the details. You'll get more exact costs of what it will take – of what the costs are going to be for the medication identified in the system impact study report as well as a more detailed schedule in the report. So in essence, the best way to look at it is the feasibility study, which is optional, gives you 100,000 level view of what will happen.

 

                                    The system impact study probably gives you a more 50,000-foot level, and the facility study dives into the details. So considered more like an upside down triangle, so to speak, if you're going to look at it visually of the granularity as we go down further on in the process. As David alluded to, there are agreements. There are always agreements throughout this process. Whether it's finding an agreement to study the work or signing the interconnection agreement itself. Now most transmission service providers upon completion of the facility study report will begin working on the large generation interconnection agreement.

 

                                    This agreement for the most part is very pro forma, which means FERC – order 890 has put out – they have a set template of what the agreement should look like. I'd say about 90 percent of it is ____ by the transmission service provider. However, once in a while, providers may put in a little bit something a little different that slightly deviates from their pro forma standard. But this is the opportunity for the transmission service provider and the interconnection customer to negotiate in several areas.

 

                                    It is not a requirement. Some interconnecting customers have chosen to do this. Some haven't. Now one of the items they may want to negotiate on is who builds the facilities. Now transmission service providers may have a preference, saying, "We will build the facilities. All work done on our substation will be done by us. However, if you want to build the line, by all means, you may do that."  Those are some of the items that may come up in the negotiation, as well as milestone of payments. For example, a transmission service provider may ask you to fund maybe 80 percent of a cost upfront, but may only perform 30 percent of the work in the first four months.

                                   

                                    Well you may find it more beneficial on your side to say, "Can we just do it at a 50/50," or some other payment schedule. So those are usually the two big items from my experience that I've seen be negotiated on. And my one thing – I'm skipping ahead. For the interconnection requests that's extremely important is your queue position. Some of you may have heard of a queue position, why is it important. Well the reason why the interconnection queue is important is that drives - _____ your queue and the timestamp of you getting your request in the queue of how the transmission service provider is going to look at your request. Transmission service providers have an obligation to consider those ahead of you in the queue when they review your study work. So for example, if you were to put your request in on April 1 of 2016, and the transmission service provider has five other requests ahead of you, when they look at your project, they will consider all the other projects ahead of you in the queue when they look at yours.

 

                                    So it can get costly on your side because the other person ahead of you in the queue may not have prevented overloads, but your generator may be the one that pushes it over the edge. Typically what we have done with our customers is we encourage them if they are seriously looking at how many generator interconnect to get that request into us as soon as possible because you never know when someone might come in the queue. I'm going to go over a couple items really briefly of some of our changes we have made in our tariff that are somewhat unique to Western if they need for an environmental review.

 

                                    Now some transmission service providers don't have this language in there. Some have, and actually some of a lot of us do it and are looking at kind of the similar language and their tariffs themselves. What we do is we require the customer upon receiving the system impact study report to begin the environmental process. Because like I said earlier, the technical work is really straightforward and simple and can get pretty much hammered out on a relatively quick schedule. It's the environment portion that may take some time. Especially if you have to go through the environmental impact study. From my experience, I've seen it go from 18 months to 24 months and cost over a million plus dollars to get done. So keep that in mind when you submit your request and that there is the environmental side. That is usually the critical path upon getting these projects done.

 

                                    So I'm skipping ahead here. Now once you do have an interconnection agreement with the transmission service provider, the next step as David alluded to, is getting a transmission service agreement. Now there are different queues for this. So you have one queue for an interconnection and another queue for transmission service. The interconnection agreement does not permit someone to transmit power over the interconnection system. It just permits you to interconnect to it. The transmission service agreement that you will have with one provider or sometimes multiple providers, that permits you to transmit your energy or rule it through or export it to wherever your power purchase agreement is.

 

                                    So hypothetically, if you were to connect it to Western System down here in the Phoenix area and you want to satisfy a power purchase agreement with Arizona Public Service, you will most likely need a transmission service agreement from Western that will allow you to transport your energy from our system into APS' system.

 

                                    And a lot of the study work is very similar. Throughout the tariff, you know it's called a system impact study followed by the facility study. That's usually what the studies are called, and they're very similar in both instances for our transmission service request as well as an interconnection request. So that's about my presentation. I tried to make up some time there. I guess at the end, we'll have some questions. That's all I have.

 

Sean Esterly:              Great, thank you very much, Jon. So we'll move right along, and in light of time, we'll go now to Scott for his presentation. And Scott, if you're ready, I can see that you're still muted, I can hand you the controls.

 

Scott T. Clow:             Okay, I think I'm unmated if you can hear me.

 

Sean Esterly:              Yeah, and handing the controls over to you now.

 

Scott T. Clow:             Okay. Bear with me. I've got to pull up my presentation here.

 

Sean Esterly:              Good to go, Scott.

 

Scott T. Clow:             Okay, so just before I get going, we had tentatively planned for me to cover some commercial scale projects that we're looking at, and Tawnie was going to do some local scale. I don't think she has any slides for that to share, so Jon, good job speeding up and getting us back on schedule, but we probably have a little more time than we needed. So I have some slides here about things that we've been working on on the commercial scale. And so we have a renewable energy committee here which includes our planning department, our environmental programs department, and our economic development program.

 

                                    And we have three potential renewable resources available to us. Our solar resources are the ones we've been focusing on because that is very well supported with data from NREL. We're also looking at a pump storage facility as the earlier presenter described. Those are becoming more – a bigger part of the energy picture nationwide, and we also are going to be looking more at wind. Our biggest wind resource here that we're aware of is on our – on the Ute Mountain, the namesake of the tribe, but that's a scared mountain and they don't want a bunch of wind turbines up there. That being said, there's some other locations on reservation trust lands that have wind potential, and we're going to be working with NREL on testing some of those.

 

                                    Then the tribe also has a bunch of land they own off the reservation that may have potential. So we haven't ruled out wind. It just hasn't been our primary focus to date. Coming back to the three I mentioned, we've done a few feasibility studies to date looking at development of solar and pump storage, and then interconnection. So on the commercial scale, solar side, we had a company approach the tribe that had an actual concentrated solar technology they were looking to build and deploy in the US, and approached the tribe in looking at different sites on the reservation that might be favorable for that. So we actually got that one for free.

 

                                    Mostly some staff time and coordinating it, but it really helped us look at where on the reservation we might actually do a commercial scale solar development. So that feasibility study was mostly a GIS model where they incorporated and weighted different factors, including cultural resources, water resources, visual resources, road access, proximity to transmission, slope aspect, and places on the reservation like the mountain I mentioned where it's just not going to happen. And then related projects. There was a small interconnection analysis in that as well, and then we – the tribe was also approached by a company that was interested in developing a pump storage hydroelectric project on the reservation here.

 

                                    They'd identified a few locations around the four corners area, and the tribe actually entered into an agreement with that entity on the beginning stages of the FERC licensing process. Unfortunately, that company was purchased by a larger one, and decisions – the decision matrix changed, and things weren't getting done, so we actually broke apart that agreement and we're no longer partners with that company, and we canceled the FERC application process until we're on firmer ground with that.

                                               

                                    With that, thanks to Department of Energy and WAPA, we did a pre-feasibility interconnection study, so what the gentleman was just talking about with an interconnection study. We did a pre-feasibility study which has been helpful. I'm not an electrical engineer, so the last two presentations were very informative and actually helping me understand this pre-feasibility study. So I've got a few slides relative to that in here too.

 

                                    This is our – the study area for the commercial scale solar. So it's pretty busy map here. The light blue boundary is the boundary of reservation trust lands, and so you can see there's a big chunk in Southwest Colorado and Northern New Mexico that are contiguous that are reservation trust lands. Then there's up to your upper left to the northwest in Utah, there's some parcels of land that are also trust lands. Those are allotted, some owned by the tribe, some owned by individuals. And also on this map, we have transmission lines. There's WAPA line, and what's identified as Utah Power and Light in some of these, which is Rocky Mountain Power. PacifiCore also has a major line running across the reservation.

 

                                    So that's just kind of a basic map of where we are relative to four corners in the western power grid. So in the feasibility study on solar, I just want to put in a couple slides that kind of show a few conclusions out of that GIS model. So Site 1, these are ranked from the best potential to the, I guess, feasible but not most desirable potential. Seven locations. Site 1, over 3,000 acres, it's adjacent to the location of the hydroelectric project, within a few miles of the WAPA 345 KV line. Within five miles of two major substations around four corners.

 

                                    We've got established roads, we have some water resources, we do have a national park and a tribal park nearby. So visibility impacts were considered in this, and then T&E species – a gentleman before Jon mentioned NEPA, and threatened and endangered species are a big part of that. So more needs to be learned about that. Similarly, Site 2, this is essentially on the top of the mesa instead of below the mesa, but same general vicinity. About 2,600 acres near the hydro project location. A little further from the transmission in the substations. Again, we have some water resources, so visible resources are impacted a little more on this one.

 

                                    We have to go up 1,200 feet to the top of the mesa, which is why we would have pump storage project there. And again, T&E species need to be studied more on that one. Gonna run through some maps here. So this is Site 1 and 2. The ones that I just described. You can see by the topography Site 2, the upper to the right there is on top of a mesa. Site 1 is below a mesa. Essentially, if we had a hydroelectric facility there, we'd try to build solar around it to power the pump backside of that as much as possible.

 

                                    This, Sites 3 and 4, actually are over on the Colorado part of the reservation, so the strange shaped in the – the strange shape in the middle there with the circles in it is actually part of an agricultural project, so that's already land being used for something. To the upper right of the slide, we also had the flank of the Ute Mountain, which is as I mentioned off limits. Looking at the topography around Canyon Country here, they're honing in on flat areas. This is pretty good water resources in the vicinity with the agricultural project.

 

                                    And then you can see there's a transmission line that's running across this slide, too. So proximity to transmission is pretty good here. Actually connecting to that could be an expensive proposition. But again, another site over in Western Colorado near our agricultural project, and even north of there, same factors considered. And then these sites are actually way down in the opposite corner of the reservation, southeast edge of the New Mexico lands. You can see there's a 345-kilovolt tri-state line running just south of our boundary in this one. They're actually building another – the San Juan basin connect line is supposed to be built on a corridor right next to that, so there's good interconnect opportunity down there.

 

                                    I should mention that there are some other planned land uses around Site 7 here that would probably preclude that site as a solar deployment site. Also this part of the reservation on this slide is very heavy on our mineral extraction. We are an oil and gas tribe, and this is pretty much the majority of our oil and gasses is down on this part of the reservation. So Site 7 and 8 probably are somewhat unrealistic. Maybe something on a smaller scale there. And so moving into our pre-feasibility interconnection study, we have an economic development director who was considering something on the order of a 25-megawatt solar facility or solar farm. And so right upfront, the study identified the cutoff of 20 megawatts that Jon mentioned in the previous presentation.

 

                                    Things in this study, this was a very helpful study for us. Again, it's a big learning curve for us, but general information about large generation, interconnect potential and processes, interconnection locations and types and costs, the cutoff, the queue processes that were just described, total transfer capacity and available transfer capacity, points of receipt, types of products, some marketing issues and concerns were described. And then there was a part that was specific to a couple locations on the port storage hydroelectric. So this slide, I wanted to just show how complicated our neighborhood is I guess. So in the four corners, Northern New Mexico, there's what's called a common bust. So there's 12 major transmission lines that are more or less interconnected, and there are more than a half dozen major customers that take power off from those. Studies have shown that it's more constrained to the west and southwest and that maybe markets to the north might be more favorable for us. And then some of these options may require another rating process through the western electrical coordination council on that. So the figure to the lower left just shows the lines, and that's part of the solar feasibility study, the interconnected component of that.

 

                                    And then the colored one on the right is from the WAPA Department of Energy study that shows a little further down into New Mexico where those lines go. The reason that we have this common bus in four corners is we have two coal-fired power plants on opposite sides of the San Juan River here. The San Juan generating station is closer to the Ute Mountain reservation, and there's a couple substations within miles that I mentioned in that solar feasibility. And then the south side of the river is the four corners generating station. And the EPA's clean air act, what they're doing now in reducing the emissions from those coal fire power plants is creating a lot of opportunities for various entities to tie into this common bus, and the tribe is very interested in that. We're hoping we can get something in the queue before other people beat us to the chase on that, but we're looking seriously at this opportunity.

 

                                    So the interconnect analysis looked at three types of connections, different levels of voltage. For the small generation, connecting into the 345 line is just not feasible. The 230 is more feasible, but it's not practical unless we plan to really build it out to a big generating station or multiple generating stations. So distance to the interconnection is a factor there. We have had one developer who was discussing stage solar photo voltaic project, perhaps in 50 megawatt stages, and it looks like a connection is justified in cost on the front end that if we were to build out 50 megawatts, it would probably justify the cost of the interconnect and the tribe would still be able to maintain a revenue stream as an economic development project with paying for that interconnect.

 

                                    That seems pretty favorable. Again, this study was based around a 25-megawatt concept, and so it didn't really consider the large scale solar or hydroelectric quite as much as that size. So the 230-kilovolt connection would be on the order of six to eight million dollars. Also part of this study was a discussion about stepping up the power from the photovoltaic array to a transmission line. So they looked at whether to transform that at the source or to transform that at the interconnect, and so it would be a little bit cheaper to do it at the substation. I think it would be an order of seven million at the generation source, and more like five million at the substation. So this diagram just shows basically what a schematic if you were to do it at the generation source.

 

                                    Additional locations considered, San Juan substation is the substation that is just north of the San Juan generating station. There's a lot of lines that would need to be crossed that would make it more expensive, complicated for safety and things. Be about 14 million to upgrade that substation and connect that from our generation source, and then with multiple transmission lines running across the reservation in different places, we looked at just tapping in and building a substation. Something on the order of $42 million.

 

                                    Now if we're looking at the pump storage hydroelectric project, that's a very expensive project, and it could conceivably justify an investment on that scale for a PV solar project that wouldn't necessarily be justified there. So in summary, the tribe has the land and other resources to build commercial scale, solar, and a pump storage hydroelectric generator. We also have potential with local electric utilities for small generation, and there's a lot of customers out there that are looking for clean energy on the large generation. So there's a lot of opportunities for the tribe and in that four corners bus there.

 

                                    The interconnect scenarios vary, a lot of challenges in planning and scaling, so the size of the interconnect, investment in interconnect, location in interconnect, they're all different. And as the previous presenter alluded to, the permitting and process team leader is going to be very influential in actually shaping what sort of project comes out of this effort by the tribe. I mentioned a developer earlier who had done some cost analysis on the interconnect and justifying that with a PV project. And if we can reinvigorate those relationships and inject some capital into it, that still has some potential.

 

                                    And then the power purchase agreement and queue dynamics that the previous presenter described in greater detail than I can, those are going to be very influential in shaping any project here. But the I guess – on the second bullet, the tribe needs to get from identifying the potential to identifying and pursuing what it really wants to come out of this besides just the conceptual ideas here. And we have so many dozens of variables and uncertainties, and we need to turn those into some solid plans and processes. And I guess the last couple things – certainly the solar is going to be on the short term, and the pump storage would be on the long-term in planning and connecting. We'd like to build one after the other, and that's definitely going to be the order of how that shakes out.

 

                                    Some of our next steps in – this is part of what Tawnie has been leading. We really want to build up some community scale projects as a demonstration to the tribal membership before embarking on the commercial scale project. So we're looking at a couple photovoltaic projects here, one to two megawatts. The town of Toyic where our offices are, the tribal seat uses between one and a half to two megawatts annually. That's average. I put it in an annual perspective because we have our agricultural project varies significantly from summer to winter and the power relative to that. But on the hydroelectric, we are actively pursuing a micro-hydro project on the canal here. We have an energy deflection structure to protect the canal, and it's just diffusing energy.

 

                                    So we want to actually harness that and generate some electrons and some revenue for the tribe. So that's going to be a small-scale project. It's already being planned and we have some partners on that. So that's probably going to be our first renewable energy project on a – approaching a megawatt scale, half megawatt. I wanted to mention we haven't looked really closely at the Rocky Mountain Power Line. An interconnect to that would probably be comparable to what was analyzed in the DOE and WAPA pre-feasibility, so we're probably looking at $40 million to build a substation to connect into that, but it's very proximate on the Colorado part of the reservation. So we're continuing to look at that.

 

                                    And then my last bullet is we really need a staff person to be the lead on this. We have an ad hoc committee as I described, and it is a goal here in the next year or two to actually create a renewable energy project coordinator who would be 100 percent focused on these projects. And instead of having a little bit of my time and a little bit of other peoples' time on it. So that's kind of where we're at with renewable energy deployment and project planning. So thanks.

 

Sean Esterly:              Great, thank you, Scott. We have one more presentation. We're going to ask Bob Easton if he can give a condensed version of his presentation so that we can still get to the question and answer session. So I'm going to turn things over once again so we can see their presentation.

 

Robert Easton:           Okay, can you see that screen?

 

Sean Esterly:              Yes, we can, Bob. Thanks.

 

Robert Easton:           All right. I'll go pretty quick. Basically, I just want to talk a little bit about the transition planning processes in the western interconnection, and basically it's the – and will continue to be a hierarchy of local, regional, interconnection wide planning efforts. Pre-ordering – now these are FERC orders. There were three or four regional planning groups put in place, and we also had the WECC planning coordination committee process that tried to work through planning processes. There was something called Seams Steering Group of the Western Interconnection that started trying to coordinate issues WECC wide, and it was the impetus for the old WSCC to become WECC. Then post FERC order 890, transmission-planning obligations, as Jon talked about earlier, of transmission providers were reflected in their _____. And that's about the time transmission planning action planning policy committee at WECC came about.

 

                                    And then in 2011, we had FERC order 1,000 that basically expanded the obligations of the transmission planning process. It was supposed to result in more efficient and cost effective transmission projects and required a regional cost allocation in this interregional coordination that I'll talk about a little bit. Now this is just a diagram of the entities – the FERC recognized planning regions in the west. The purple is west connect, the brown is NTTG, and the _____ transmission groups. Blue is ____ grid, and of course the yellow there is California ISO. Just a quick overview on each of those. The ISO came about – it's actually April 1, 1998. I was in our Phoenix office when that happened.

 

                                    The _____. It was okay. They were the first region in North America to fully comply with order 1,000. They have a three-tiered three-base planning process, so basically you can see on the left side they do a planning process that takes about three months. Actually do the studies in 15 months that results in the approval or transmission plan by the ISO governing board, which they just approved their 2015/16 plan report last Friday, and it's posted on their website. And then they have a competitive solicitation phase if they go out for bidders to build their projects.

 

                                    NTTG was formed in 2007 to conform with 890 process. It's basically an unincorporated association of transmission planners. You see in the lower left there – and they collaborate with their state representatives, and today, it's a FERC order 1,000 planning region, and their facilities are in the red there in the diagram. Colombian grid is the next one there in the Pacific Northwest, and they have what they call a planning an expansion functional agreement, _____ agreement that they've updated to address order 1,000 issues, and they are – the participants are listed in the lower left there.

 

                                    The last one, I'll just cover it's west connect, came about in 2007. The initial coordinator planning agreement was formed with a planning management committee, and that was to satisfy 890, and then down in the lower – the restated agreement was signed in 2014/15 where 15 TOs have signed on. West Connect is a little unique because it has two membership categories in the transmission owners with load storing obligations. They called it an enrolled member. The jurisdictionals had to sign into that where they are subject to mandatory cost allocation. Then they have a coordinating transmission owner category that can basically opt out of mandatory cost allocation. That's the only way to get the non-jurisdictionals to join into this group.

 

                                    I talked a little bit about one of the requirements of more than 1,000 that's supposed to implement this interregional planning coordination. Basically, there's no formal document that documents this process, and there have been interregional coordination efforts today if you try to facilitate at the WECC level. And basically, the interregional process is supposed to commit people to do a better job of coordination, have a formal procedure and commit to maintain the method of communications that goes on in this interregional planning idea. Those four regional planning entities I just mentioned have gotten together, and they've gotten the language they've filed in their tariffs all the same in this interregional process, and we've had three coordination meetings over the past two years, February of '15, August of '18, and this year earlier, February, we had the third of those, and we're trying just to get a documented process where we will do coordination between each of those four regions.

 

                                    The next meeting is slated for February 23, 2017, and it'll be at NTTG's office in Portland. These next two slides have just outlined if you can see on the left an ISO Colombia grid NTTG and West Connect processes. Basically, it's an eight-quarter process. The ISO as you recall was about an 18-month process, so they're a little bit off. Those there have a very similar process. This is just the first year where basically that will identify regional needs. Second year, the last four quarters is to identify interregional needs and do the economic analysis and develop and do developer solicitations to provide bids to do any of the interregional projects and they're identified.

 

                                    And just going forward, NTTG and ISO, they're in full compliance with the interregional process, Colombia grid and West Connect. Awaiting their orders. An update on this is they did receive the compliance orders in October of '15, so we're all compliant with the interregional planning process, and now we're just turning our attention and trying to look at the differences. As you know in those swim lanes, there were three of us that are aligned, and the ISO always do a little different. We're still struggling with that to try to make sure we all line up.

 

                                    And challenges remaining are just to ensure consistency in the planning, and we're all implementing the NTTG plumbing grid and West Connectors implementing cost allocation in the project developer process this year in 2016, and the ISOs basically had several iterations of this, and they had awarded at least one project outside of their ____, which was Colorado Delany River just this last year. That's a very condensed version. We can move on. Thank you.

 

Sean Esterly:              Great, thank you very much, Bob. Sorry about rushing you through that, but do appreciate the condensed version there of your presentation. So we'll move ahead now right into the question and answer session, so we have all our panelists available to answer questions from the audience. Again, audience, have any questions, you can go ahead and do the question pane. We did receive a couple during the webinar, so I'll start with those. These questions again are for any of the panelists. First question is is there enough current energy resource by region to support a larger fleet conversion to all electric fleets. And if not, what would be needed to meet say five percent of current city service fleet conversion. And that question, looking at electric vehicles, perhaps we could also take that one offline and answer post webinar. I'll move onto the next one then, and perhaps we can come back to that one. The next question asks will corporations that want to make large-scale reductions in energy usage or conversion to energy efficient systems be entitled to state or federal incentives?

 

David Narang:            This is Narang. This question pertains to state or federal incentives for energy efficiency? Is that – did I understand that correctly?

 

Sean Esterly:              It would seem so. It's referring to large-scale reductions in energy usage or conversion to energy efficient systems.

 

David Narang:            So Sean, I'm not sure if your group is tracking this on the energy efficiency side, but we should follow up on that. I believe there are energy efficiency – maybe some clarification on what large scale means. I’m not quite sure – there are incentives, certainly.

 

Sean Esterly:              Definitely, yeah. We can – we can follow up with this offline as well. So we can do that for the attendee that submitted that. We do have a couple hands raised in the audience. So those folks with hands raised, I'm going to go ahead and unmute you one at a time. we're going to go first to Dusty Miller who has their hand raised, and I'll unmute you, and you can ask your question directly to the panelists. Dusty, you should be unmated if you want to go ahead and ask your question.

 

Audience:                    Hi, this question is for Scott, and I was wondering if you have any suggestions about how a consulting and engineering company could get the word out there that we're interested in helping tribes to develop environmental documents in studies for these kinds of projects like you were talking about.

 

Scott T. Clow:             Yeah, I mean direct contact is good. I mean we're on the interweb if you Google us. You'll find our website and our contact information, Cross the Tribe or our environmental programs department. So direct contact I would say is good. I’m not sure that any of the federal entities can really steer private consultants towards direct – towards projects directly as far as their legal limitations. I guess paying attention to what projects might be happening and then direct contact I think is the best.

 

Audience:                    Okay, that sounds great. Thanks.

 

Sean Esterly:              Great. We'll move onto the next attendee with their hand raised, Scott Griffith. I see that you have your hand raised. So I'm going to go ahead and unmute you. Go ahead and ask your question to the panelists.

 

Audience:                    Yes, actually, I guess a question I work with a lot of tribes in New Mexico – and one of the issues we have here is we're gridlocked for projects, so are you guys working on any basically community size – are there some incentives for let's say community sized projects that actually can't get on the grid as it is? Most of the tribes in New Mexico are going to have a very hard time getting large enterprise style projects because of that. Have you guys addressed that _____ Mexico project?

 

Sean Esterly:              Would anyone like to weigh in on that? Scott, perhaps we can share – I can share your e-mail address with the panelists, and we can address that one after the webinar.

 

Audience:                    Yeah, that would be great. Appreciate that.

 

Sean Esterly:              Yeah, will do. All right, we'll move ahead to the next question from the audience. This one is going to be from Tim Moore. You're unmated now. You can go ahead and ask your question. Tim, you're still muted on your end, if you want to unmute and ask your question. All right, we'll move onto the next question. Matt Rankin, you can go ahead now. You're self-muted, but if you unmute from your end, you'll be able to ask your question. Matt, you're still muted. All right, we'll move ahead then. Up to this point, that's all the questions and all the hands up we had, so to the people that we said we would take your questions offline, I will go ahead and pass your e-mail addresses along, and I'll also right now display e-mail addresses of the panelists. If you want to go ahead and reach out to them, please feel free to do so. And we can get to those.

 

                                    You can communicate directly with them. So with that, I do appreciate everyone hanging on as we went over our time limits a little bit, but we're going to go ahead and end the webinar at this time. Please feel free to provide feedback on the presentations today, and we're very interested in your suggestions and how to strengthen the value of the webinar. And also here is some links to where you can follow up on additional webinars. The next webinar is understanding the energy policy and regulatory environment on April 27. Thanks again for your attendance and attention, and I hope everyone has a great day.

 

[End of Audio]