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Solar Hedge for Gas Price Risk

Most utilities now face some sort of renewable portfolio standard (RPS), but is that all that drives investment in greener generation assets? Green Utility spoke with Brad Albert, general manager of energy resource acquisition and renewable energy at Arizona Public Service (APS), about why the regulated utility has decided to exceed that state’s renewable energy requirements.

GU: What’s driving your investment in renewables right now?

BA: It’s really two things. The RES [renewable energy standard] really sets the floor, but through our research and planning process we looked at other factors we thought were important in the long term, such as price stability and energy source diversity, and even the fact that some of our customers are say they want more renewable energy. Factoring all that in, we actually are on a trajectory to substantially exceed that RES standard.

GU: Does APS own and operate any renewable generation assets?

BA: The ownership perspective has only been a recent addition. AZ-Sun is a program for us to install and own 100 MW of solar photovoltaics (PV), a utility-scale application. The other renewable energy we use -- the wind farms, the geothermal plant, and particularly the large-scale solar-thermal plant -- those are all PPAs. We do own some small solar installations -- currently about 5 MW. Those are very small projects around the state.

GU: I understand that currently you have about 288 MW of renewable energy in your portfolio. What percentage of your overall energy profile is that, and do you see that ratio changing in coming years?

BA: Right now, renewable energy is around 3 percent of our total energy. By 2015, we aim to get to 10 percent to 11 percent of retail energy sales coming from renewable energy. That’s a little bit more than double what the RES would call for in 2015 [editor’s note: Arizona’s RES calls for approximately 5 percent of retail sales to be served by renewable generation by 2015, and 15 percent by 2025].

GU: How do you calculate the value of renewables in your portfolio?

BA: That’s a very dynamic equation. In just the last year, for example, we’ve seen significant declines in the price of solar PV. The technology, the pricing, everything continues to evolve rapidly.

GU: Some experts say PV prices have been dropping at a stable, predictable rate and that cost parity may be little as seven or eight years down the road. Do you pay attention to those kinds of projections and do they influence how you spend your money today?

BA: We definitely spend a lot of time looking at price trends, thinking about what-if scenarios. My luck has not been very good in terms of predicting the future, but we certainly see solar PV as having that potential. It still has a ways to go. Even in a region like ours, where you have probably some of the best solar conditions in the world, it’s not currently competitive with conventional generation. It’s still very dependent upon the federal investment tax credit, tax subsidies. Then again, it has gotten closer and closer to conventional alternatives over time. Your guess is as good as mine as to when it actually gets to a point where it can survive on its own and is competitive compared to conventional alternatives, without tax subsidies.

GU: What types of renewable generation do you see as having the best potential for eventual cost parity?

BA: Wind is not really an option for us. We have a couple of wind projects in New Mexico, but we don’t have capacity for anything more coming from that end of the world. The cost of building transmission to get more wind makes it cost-prohibitive. It really comes down to solar as a driver down here in Arizona. The renewable equation essentially is a solar equation for us in the long term. From a technology perspective, we’ve looked at solar thermal; we’ve got the big [250 MW] Solana generating plant under construction. That’s a PPA with Abengoa Solar, a Spanish company. But clearly we’re seeing solar photovoltaics being the much better value proposition for us now than the large-scale thermal projects. They have a lot of advantages beyond just price, especially scalability. You can implement them in small projects, in the 15- to 20-MW range, add them in bite-size pieces, versus having to build a large-scale thermal plant.

GU: Is there a particular type of PV that you’re working with?

BA: It runs the gamut. We haven’t seen one technology distinguish itself from the others yet, so that question is still playing out. We are deploying both thin-film technologies in a fixed orientation, as well as a number of crystalline in single-access tracking. And they both look fairly close; it’s neck-and-neck right now.

GU: The smart grid will ostensibly make integrating intermittent resources a lot easier. Does that figure into the valuation process as you fund these projects?

BA: We’re trying to get our arms around exactly what that means from a valuation perspective. We’ve deployed a couple of interesting projects as the basis for studies we will conduct over the next year or two that will help answer that question. Up in Flagstaff, we’re deploying a high penetration of rooftop solar systems on a single distribution feeder to look at what that means for our delivery system design. We’re deploying an energy storage project in Q3 of this year to look at how that can help change that value proposition also.

GU: You have a lot of distributed PV generation, both residential and commercial. How does that fit into the valuation mix for you?

BA: One of the unique features of our state RES is that it stipulates that 30 percent has to come from distributed technologies. So we provide aggressive incentives to our customers, both residential and non-residential, to install rooftop solar systems. Somewhere north of 10,000 customers have taken advantage of those incentives and deployed solar technology.GU: A lot of utilities have balked at distributed generation because they see it as a threat, almost a kind of competition. How do you fit it into your business model?

BA: We’re exploring alternative business models in deployment of distributed energy. One of the unique aspects of the Flagstaff high-penetration deployment is that the systems installed on the customer rooftops are actually utility-owned. The customer gets a special tariff from us for being a solar system host. This year we are deploying the same model to schools and government buildings, so there is a utility-owned segment of our distributed generation requirement.

GU: Politically, people tend to think of Arizona as a red state. It’s certainly not California or Vermont when it comes to the cultural sensibilities that often drive renewable energy policy. How does that play into things like your decision to exceed the state’s RES?

BA: You’re hitting on a key aspect there, because this state, at least the way I view Arizona, will be much more cost-conscious about it. We have to balance the aggressiveness of our renewable energy deployment versus the rate impact that we’re putting on our customers.

GU: Can you attach some numbers to that? Do you compare traditional generation to renewables on a straight a cost-per-watt basis?

BA: We do that through our procurement and resource planning processes, but we tend to keep those internally just because of the competitive nature of it. We want to make sure that we’re not giving too much information to the marketplace, that we can still maintain and get the best deal on behalf of our customers. I will give you something we put out there publicly a couple of years ago when we signed a PPA. At that time we were estimating that project was about 20 percent higher than the cost of a conventional alternative. That was a long-term projection. It’s probably had more of a price impact upfront, versus the long term, which was where the benefits were, but overall about 20 percent higher.

GU: And is that comparable to your other renewables projects?

BA: It’s not out of line. It’s an ever-changing equation, because -- certainly now in 2011 -- our conventional generation alternatives have gotten a lot cheaper because natural gas prices dropped significantly over the last couple of years. That’s a key variable. We are under 40 percent coal, about 27 percent nuclear, around 30 percent natural gas, and the rest -- 5 or 6 percent -- come from renewables and energy efficiency. I’m rounding numbers so it may not add up exactly right, but that gives you a ballpark estimate. But what we really use as a source of comparison is natural gas generation, because we don’t intend to build any new coal-fired generation, nor in the next 15 years do we see ourselves building new nuclear generation, so our incremental conventional generating sources in the next 15 years are natural gas-based.

GU: Do you see anything that might drive up gas cost and shift the equation?

BA: Just that natural gas prices are incredibly volatile and variable. Right now they’ve been hovering in the $4 MMBtu range, largely because of the shale gas exploration and production that’s coming into the marketplace and keeping prices down. And the economy obviously isn’t up and cranking like it was three or four years ago. But three years ago we were looking at $13 or $14 per MMBtu.

GU: So in stacking PV solar, for example, against natural gas, you’re talking about two moving targets.

BA: Right. And another thing we pay attention to is the diminishing value that we get from solar PV that’s deployed on our system as we deploy more of it. It becomes less and less effective in terms of meeting our peak load obligations, as you deploy more of it, simply because the timing of when solar PV is produced doesn’t synch up perfectly with when our customers demand the most amounts of energy.

GU: What’s the biggest lesson you’ve learned in valuing renewables?

BA: Just to be flexible. We’ve seen this marketplace evolve very rapidly, and I hesitate to make any predictions about what’s around the next corner. We’ve just been a believer in diversifying, not putting all of our eggs in one basket as this marketplace continues to evolve.