WAPA Questions and Answers

• “Who is CRSP? “

Presentation by Lynn Jeka (WAPA) on 8/9/2013 at the AMWG Meeting Question and Answer Portion (starting with last three PowerPoint slides)

• Lynn Jeka: I don’t want to trivialize how complicated this is. Think about your checking account. You get a salary. It gets deposited into your bank account over time, every week, every two weeks, monthly. You’ve got revenue coming in over time. And then you’ve got all your expenses that have to be paid for with cash. We’re the Federal Government; we don’t have a credit card. We have to have cash. So let’s use the example of you want to buy your daughter a car that’s $1,000. Do you go back to your boss and say, “Gee, can you give me more money because I had to pay $1,000?” It’d be nice, but it doesn’t happen. We don’t go back to our power customers and say “I just spent $24 million on a transformer, can you give me more money?” So think of this as a great big checking account. Granted we have $115 million in our checking account but it goes fast when you pay $24 million for a transformer. So we’ve been talking about the concept of non-reimbursable activities. So if the reimbursable activities are the ones that the customers have to pay for, non-reimbursable are the ones they don’t have to pay for. For example, we contribute to the Adaptive Management Program. That’s non-reimbursable. So what the Government did when they created the CRSP, is they said we recognize that you’re going to take cash out of this Basin Fund, you’re going to use it for activities that are not included in your rate. So in order to make the customers whole, we have what’s called a constructive return. And essentially what the Treasury says is for every dollar you spend for non-reimbursable activities, we’ll give you credit on the principle and interest that you owe us. It will be as though you repaid it. But what happens is there is no revenue coming in for these activities; it’s just a cash outlay. So this whole process becomes a tremendous cash management and cash flow challenge. So what happens in a drought? The power rate doesn’t change. The revenue doesn’t change. What changes is the amount of power we have to purchase to firm those contracts. That’s straight cash on the Basin Fund. That means there is that much less money for operating and maintaining the dam, reimbursable activities. It just becomes a huge juggling act and we’re very good at it. And if I wasn’t, you’d have somebody else speaking next time. So what are some of these programs that we’re allowed to treat as reimbursable? You have the Upper Colorado Recovery Fish Program, San Juan Recovery Program, the GCAMP, and the Salinity Control Program which actually helps reduce the salt in the Colorado River as it flows down to Mexico. The problem was that when we were delivering our treaty water to Mexico, it was so full of salt that it was practically unusable. All of these things are cash that come out of our checking account to fund these various activities. So when things happen at the dam - our water is constrained, generators are out, and our ability to produce power is somehow diminished – it has a huge impact. It reduces our ability to deliver our power to our customers and it has a significant impact on our ability to support further liability. As a federal agency, we are also absolutely required to make sure that we comply with Section 106.

So to sum this all up, so what’s the benefit of having a CRSP? Well, first of all there’s that nice, clean, non-polluting hydropower that you all get for a reasonably inexpensive price. We maintain the dam and all the transmission lines to make sure that everything is operating well. We don’t like saying no to Jason Tucker (GDD Manager) when he needs money for turbine runners and things like that. We’re unique as a federal agency in that we’re paying back the taxpayer money that was spent to build the dam. That $2.3 billion is taxpayer money that has been invested in the dam and we need to pay it back. We fund great programs like the Adaptive Management Program, the various fish recovery programs, and one of the other things we pay for and have certainly been talking about are these high flow experiments. So where does that money come from? As you heard from Katrina yesterday, there’s an annual release volume of water that doesn’t change. So what CRSP does is work very closely with the Bureau of Reclamation to re-juggle the water. We need more water in November. Where is it going to come from? Some other months? Why does that cost us money? You’re still producing the same amount. Yes, but. You’re producing it a different month and all of a sudden I’ve got more money in November than I need and less in the other months. I’m producing at a time of day that I really don’t need it. I’ve got two peaks a day in the morning and evening. I don’t need power at midnight, but in a high flow experiment the water is running. And then there’s all the water that goes through the bypass tubes when we exceed powerplant capacity and we’ll never recover that. That’s an opportunity lost because that’s revenue we don’t generate. So there are price fluctuations depending on the time of year that we’re buying or selling power. There may not be as much demand in November for that excess power so we’re selling it for less than we’re going to have to buy for come February or March. There’s the time of day difference. Buying and selling power on and off peak creates a price differential and then there’s the money lost down the bypass tubes. On the back table you will find handouts of the Western Annual Report, power fact sheets, and other things. I’ll just open it up for questions.

• Sam Jansen: Thank you. That was really informative for me. You told us how much the system owes so I’m wondering what the number is on Glen Canyon Dam for that construction?

Lynn Jeka: I don’t know that exactly offhand, but we have a repayment period on dams of 50 years. Glen Canyon Dam is just about 50 years old so I would probably say little, but I don’t have the exact number.

Sam Jansen: How would that affect things, like how much do you pay each year on Glen Canyon Dam? I’m curious what happens when you’re done paying your mortgage on the dam.

Larry Walkoviak: We have a mind numbingly complex, bureaucratic repayment system for CRSP. I wish it was not so, but it is. In that $2.5 billion that Lynn is talking about, there is aid to the Jensen Unit and other irrigation components. Those kick in at different times and so it’s not exactly a straight line so just because Glen is about 50 years old, there isn’t a straight line.

Lynn Jeka: Our customers are adding debt every time a generator is replaced or turbine runners are re-done, it adds to the debt that we owe back.

John Jordan: There was a number assigned to loss revenue for the HFE last fall, wasn’t there? Was there a number we saw that related to that and that number was about how much?

Lynn Jeka: I’ve seen numbers varying between $1.1 and $1.4 million, but that number won’t be final until the end of the water year so that’s the end of water year 2013 and then Argonne as an independent facility calculates that actual loss for us. That’s the estimate range.

John Jordan: Whatever that number was, in the example that you put up, if that was indeed absolute lost revenue at the end of year when you were doing your distribution, what was charged back to customers and what was credited against the charge to the Federal Government for the dam? Which part would that go into?

Lynn Jeka: The non-reimbursable.

John Jordan: So that reduces the amount of debt that you have with the Federal Government?

Lynn Jeka: Yes, but it also took $1 million out of the Basin Fund and so it’s not really lost revenue, it’s additional expense. So that was $1 million that essentially we bought more power than we would have otherwise. I still have to deliver my contracts or Ted Rampton is going to sue me.

Larry Stevens: You said 130 long-term customers, do you have short-term customers as well, or is that your main client?

Lynn Jeka: That’s our main focus.

Larry Stevens: And total number of people served?

Lynn Jeka: Leslie, do you know?

Leslie James: Just CREDA members who are not all the CRSP customers, but the majority is probably around 5 million.

Sam Jansen: When you have to buy power, who do you buy that from? Like on the market, is it federal or private?

Lynn Jeka: It’s from whoever will sell it to us. It may be other federal entities. We might be buying from the Loveland projects up north in the Rocky Mountains, Tri-State, or whoever has power to sell. We’re looking to buy.

Ann Gold: To follow on to that, do you have choices? For instance there might be four entities that are willing to sell you power. How do you choose?

Lynn Jeka: The cheapest. We’re looking to buy in big blocks. We’re not buying an hour here or there. We’re buying 50 or 100 hours.

Ann Gold: And then my question is that both you and Larry both mentioned the aid to irrigation component and wonder if you could explain that more.

Lynn Jeka: As part of CRSP, there are what are called participating projects. For example, the Central Utah Project which delivers water into Utah, is part of CRSP. And so the CRSP Act requires that power customers assist with those irrigation projects in paying them off on behalf of the Government. And actually Reclamation calculates that number for us.

Ted Rampton: An assist is really code for subsidy and it only applies to irrigation projects; it does not apply to municipal and industrial. The reason for that is when the CRSP Act was put together in the 1950’s, they wanted to do all this water development but the farmers didn’t have the ability to pay for those projects and so they turned to the power revenues as a subsidy to those projects.

Lynn Jeka: Thank you Ted. That’s a good explanation.

Sam Jansen: One thing I’m often wrestling with me is when we talk about how much an HFE costs and how many millions of dollars and is WHO are the people affected? I understand this is very complex and it doesn’t make sense to just say there are this many million users so it costs them each a nickel or whatever. Who are the real people that are affected and how are they affected? I’m getting a sense of the big numbers and how it affects this process but this almost seems like a bucket of rules and money that gets shifted around. I don’t have a great sense of how it affects actual people.

Lynn Jeka: It doesn’t. That’s the simple answer because it’s not non-reimbursable so it’s not in the power rate so nobody pays. It’s not tractable back to power rate because it is a non-reimbursable activity, but that million dollars that I spend on an HFE is a million dollars I don’t have to spend on operations and maintenance.

Leslie James: The other kicker to that is when the Basin Fund gets drawn down, so you have a lot of purchases and maintenance, the Basin Fund has to maintain a balance. If the Basin Fund gets to down to a balance that is basically unacceptable, it’s part of the rate. There is a thing called a Cost Recovery Charge (CRC) and I think for you guys that live in Flagstaff, APS (Arizona Public Service) maybe has a fuel adjuster in their rate like if the fuel goes crazy. So an “adder” kicks in and that then directly affects the power customers because they get a new additional charge added to their monthly bills. And so the cash flow, granted those non-reimbursables aren’t in the rate, but they’re clearly a cash impact so if the Basin Fund because of all these requirements gets to a point, Western had to kick in a CRC and that’s a direct, immediate charge to the power customers.

Lynn Jeka: It’s not impacting the base rate but what’s happening is that because this purchased power element is going up is we go back to the customers and say if you want us to basically continue delivering that contract, then we need help because this is getting too low for us to continue to do this. So we add that supplemental charge on that says until this Basin Fund gets back up to a certain level, we need you to kick in more cash to help offset this purchased power.

___: How often does that happen?

Ted Rampton: Once. One time it was – you know this is a good way to explain it. Back in the early 2000’s when the market was crazy in California, at that same time CRSP generation was flat for summer so the market went 10 times, 50 times the normal price but yet Western was on the market trying to buy that and so that Basin Fund drained really, really fast because they had to make payments on that purchased power that was influenced by the market and that wasn’t available for generation. And so the Basin Fund almost went to zero and during those days, Western was really upset and fretting because they can’t go negative on the basin fund and so they had to kick in a CRC as a surcharge so that they could keep that Basin Fund in the positive territory.

Lynn Jeka: As I mentioned, we don’t have a credit card so we have to pay cash for everything so if this goes negative, I go to jail because I have spent more money than I had to spend and that is against the law.

Ted Rampton: Just one thing to add too in helping to explain this cash flow situation, you have to remember that the credit against repayment doesn’t apply until nearly at the end of the repayment schedule. We don’t realize the benefits of those kinds of things until the project starts to repay late in the repayment schedule.

Gerald Myers: That lower limit that you try to maintain the fund above, is that regulated or is that just based on your experience?

Lynn Jeka: Experience. There’s a trigger in that CRC that Leslie is talking about that if this fund drops either by more than a certain percentage per year or below a certain balance, then it will trigger that CRC.

Gerald Myers: Are there any limits on the upper side of that fund that can be held?

Lynn Jeka: If we hold too much money, the Treasury will ask why it isn’t being returned so we do have to – in a sense that justifies a balance. So if most of them are sitting on $300 million, people are going to wonder why aren’t you sending it back.

Steve Spangle: So who makes decisions or authorizes your non-reimbursable expenditures? Who decided that we’re going to spend $2 million on the San Juan or $10 million a year for this program? How are those decisions made?

Lynn Jeka: I can’t answer that, but Leslie has her hand up.

Leslie James: For each of those programs, there is federal legislation that sets the obligation and then they’re different. For the Glen Canyon program back in 2000, there was an amount set that is escalated by year by the Consumer Price Index (CPI). For the Upper Basin and San Juan Recovery programs, those are fixed in the legislation and, in fact, earlier in January there was an amendment that extended the power revenue funding of those programs. So the amounts are set by Congress in the legislation. The same thing with the Salinity Program. It’s a real convoluted set of laws and formulas, but they’re all established by Congress.

Lynn Jeka: I’ve only been on the job for six months so the fire hose is huge and I’m little, so I appreciate Leslie’s great background knowledge on some of this stuff.

Steve Spangle: I thought a great, big checkbook came with the job.

John Jordan: All we’ve talked is some circumstances where you had to go out and buy power, but you must be generating power that you sell also. When you sell that power on the market and it’s above the needs that you need to meet your requirements, does that flow into the Basin Fund?

Lynn Jeka: Yes.

Ted Rampton: Seriously, 1983, 1984, and 1985 when the reservoirs were full, they were generating a lot of power that goes into the Basin Fund. A couple of years ago they were generating excess because of the hydrology and that’s what Larry was talking about the way they design - the cash flow and the repayment is based on the swings in hydrology. They knew that there would be some years they couldn’t make repayment and so that’s why they had the Basin Fund. And there would be some years that great hydrology and that’s when extra money goes back to the Treasury for repayment.

Michael Yeatts: Thanks for doing this presentation because this is one of those really confusing areas at least from my perspective. Is there some legislation or guidance or how is it determined how much capacity you’re going to have available for selling to put into those long-term contracts? I’m asking it because it looks like we may be coming up to a low water year so obviously you’re not going to be able to produce as much and depending how much you’re entering into contracts saying that we can deliver really influences how much you have to buy or how much you sell. How is that done? What’s the guidance?

Lynn Jeka: It’s relying a lot on the hydrology forecasts. We enter into 20-year contracts so our current contracts are due to expire in 2024. So actually starting in the next couple of years, we’re going to be starting with what’s called a “remarketing plan” where we’re going to look at how much power we’re going to have to deliver and some of that’s going to be a function of the results of the preferred alternative which will have an impact on the capacity and the amount we can deliver, depending on how the flows are – are they steady flows, fluctuating flows? That’s going to be a huge driver in setting those contract rates.

Ted Rampton: That was a great answer. It was a great question.