Portland General Electric Co (POR) 2015 Q4 法說會逐字稿

Good morning, everyone, and welcome to Portland General Electric Company's fourth-quarter and full-year 2015 earnings results conference call. Today is Friday, February 12, 2016. This call is being recorded, and as such, all lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer period.

(Operator Instructions)

For opening remarks, I would like to turn the conference call over to Portland General Electric's Director of Investor Relations, Mr. Bill Valach. Please go ahead, Sir.

Thank you, Candace, and good morning to everyone. I'm pleased that you are able to join us today. And before we begin our discussion this morning, I'd like to remind you that we have prepared a presentation to supplement our discussion today, which we'll be referencing throughout the call. The slides are also available on our website at PortlandGeneral.com.

Referring to slide 2, I'd also like to make our customary statements regarding Portland General Electric's written and oral disclosures and commentary, that there will be statements in this call that are not based on historical fact, and as such, constitute forward-looking statements under current law. These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today. And for a description of the factors that may occur that could cause such differences, the Company requests that you read our most recent Form 10-K and Form 10-Qs.

Portland General Electric's fourth-quarter and full-year earnings were released via our earnings press release and the 2015 Annual Form 10-K before the market opened today. And the release is available at our website at PortlandGeneral.com. The Company undertakes no obligation to update forward publicly any forward-looking statements, whether as a result of new information, future events or otherwise. And this Safe Harbor statement should be incorporated as part of any transcript of this call.

As shown on slide 3, leading our discussion today are Jim Piro, President and CEO; and Jim Lobdell, Senior Vice President of Finance, CFO and Treasurer. Jim Piro will begin today's presentation by providing updates on our operational performance, on Carty construction, our service area economy, and our integrated resource plan. Then Jim Lobdell will provide more detail around the fourth-quarter and full-year results, our financing and liquidity, and discuss our outlook for 2016.

Following these prepared remarks, we will open the line up for your questions. And now it's my pleasure to turn the call over to Jim Piro.

Thanks, Bill. Good morning, and thank you for joining us. Welcome to Portland General Electric's fourth-quarter and full-year 2015 earnings call.

In 2015, we achieved several key objectives towards meeting our customer's energy needs, and I'm pleased to share our results with you this morning. On today's call, I'll provide an overview of our financial results in 2015, and initiate 2016 earnings guidance; give you an update on our operating performance; provide an update on construction at Carty; summarize the economic conditions in our operating area; and outline the status of our 2016 integrated resource plan.

Following my remarks Jim Lobdell will provide details on the fourth-quarter and annual financial results, and end with our key assumptions supporting our outlook for 2016. So, let's begin.

As presented on slide 4, we recorded net income of $172 million, or $2.04 per diluted share in 2015 compared with net income of $175 million, or $2.18 per diluted share in 2014. This decrease in earnings per share was largely due to a record warm winter that resulted in lower residential energy sales compounded by lower-than-budgeted hydro, wind and the associated lower production tax credits and higher replacement power costs. Management took prudent actions, and through temporary operation and maintenance reductions, offset approximately $0.09 per share of the financial impacts from weather and power cost.

Now looking ahead for 2016, we are initiating full-year earnings guidance of $2.20 to $2.35 per diluted share, which reflects warmer-than-normal weather and lower wind production in January. Jim will provide more details later in the call.

Now for an operational update on slide 5. Employees across the Company did an excellent job in 2015 of improving efficiency, reducing costs, and executing our business strategy to deliver value to our customers, shareholders, employees and the communities we serve. Our customer satisfaction remained very high in all segments. Residential, business and key customers placed us in the top quartile or better for satisfaction, favorability and trust, according to the latest survey results.

Also, our 2015 generating plant availability was excellent at an average of more than 92% across all of the resources PGE operates. 2015 was the warmest year on record in Oregon. This affects -- the effects of weather impacted earnings by reducing energy deliveries to the residential sector, especially during the first quarter. As a result, management not only took actions to temporarily reduce operating and maintenance costs, but also worked diligently to ensure our delivery system and generating facilities operated extremely well. These actions were critical factors in helping to address the challenges posed by weather and higher power costs throughout the year.

In 2015, we continued to demonstrate our leadership in delivering renewable energy and other programs to our customers. In addition to maintaining our standing as the number one renewable program in the nation, we won new awards, established a new offering for our customers, and hit a new milestone. Our achievements included PGE's two wholly-owned wind farms were recognized for being both safe and sustainable.

Our newest windfarm, Tucannon River, is the first energy project in the nation to win the Envision Sustainable Infrastructure Gold Award from the Institute of Sustainable Infrastructure. This award was based on PGE's contributions related to quality of life, leadership, resource allocation, the natural world, and climate risk.

Our other windfarm, Bigelow Canyon, earned a Safety and Health Achievement Recognition award, referred to as SHARP, from the Oregon Occupational Safety and Health division. This is the first time a wind project has qualified for SHARP certification in Oregon, and only the second wind project in the United States.

Also we enrolled -- also we opened enrollment on a new renewable power option that enables customers to purchase output from a new 3 megawatt solar installation in the Willamette Valley, providing a way for more customers to support solar generation. And finally, our dispatchable standby generation program passed the 100 megawatt mark. This cost-effective customer program helps meet regulatory requirements for non-spending reserves. I am very proud of these achievements.

Now turning to slide 6 for an update on our Carty Generating Station. On December 18, we declared Abeinsa, our engineering procurement and construction contractor on Carty, in default under multiple provisions of the Carty construction agreement, and we terminated the agreement. As part of the original construction agreement, PGE required Abeinsa to provide a performance bond to guarantee satisfactory completion of the project in the event Abeinsa failed to fulfill their contractual obligations.

The performance bond was provided by two sureties -- Liberty Mutual Maturity, and Zurich North America -- for $145.6 million. Following termination of the construction agreement, PGE, in consultation with the sureties, brought on new contractors, and construction resumed during the week of December 21, 2015. Currently, we estimate the total capital expenditures for Carty will be in the range of $620 million to $655 million, including AFDC, and before considering any amounts received from the sureties under the performance bond. And we are targeting an in-service date in July of 2016.

The prior Carty construction estimate of $514 million in capital costs, including AFDC, was approved by the Oregon Public Utility Commission in the 2016 general rate case. We are currently in discussions with the sureties regarding their obligations under the performance bond. And we believe they have an obligation under the performance bond to contribute funds towards completing the Carty project.

In the event the total cost incurred by PGE for Carty, less any amounts received from the sureties under the performance bond, exceeds the OPUC approved amount of $514 million, or the plant is delayed past July 31, 2016, the Company would pursue one or more avenues for regulatory recovery.

With regard to an update on the actual construction, all major components are on-site, and there are currently more than 700 construction workers on-site, representing key contractors, including Day & Zimmermann, Sargent & Lundy, and Black & Veatch.

Now let's move to slide 7, where we provide a summary of the Company's current capital expenditure forecast from 2016 to 2020. These amounts potentially could be augmented with incremental investment related to natural gas supply, system reliability, and operational efficiencies that provides value to our customers. In addition, the graph does not include any potential capital projects from the outcome of our 2016 integrated resource planning process. We will continue to provide updates on our capital expenditure forecast in future earnings calls.

Turning to slide 8, Oregon continues to exhibit several positive economic trends. First, unemployment in Oregon in December was 5.4%, and approaching the range considered full employment. Unemployment in our service area was even lower, at 4.7%, and compares favorably to the US unemployment rate of 5%.

Secondly, overall business expansion and new real estate investments continued in 2015. Investors have targeted Portland as a desirable West Coast location, as evidenced by the large number of real estate transactions during the year and proposed new projects.

With growth in both the number of local startups and in large Silicon Valley companies locating offices in the region, the Portland metro area has become one of the fastest-growing areas for high-tech employment. In addition, large high-tech industrial customers continue to expand our service area and contribute to weather-adjusted load growth of more than 2% in 2015 over 2014. This is net of approximately 1.5% in energy efficiency, and excludes one large paper company, who ceased operations in late 2015.

Finally, Oregon was once again the number one state for in-migration in 2015, according to a study from United Van Lines issued in January 2016. This is the third year in a row that Oregon has received the number one rating.

PGE's average customer count continues to increase at approximately 1% year-over-year. And looking forward, we expect weather-adjusted load growth in 2016 of 1%, net of approximately 1.5% of energy efficiency, and excluding the one large paper company.

On to slide 9. With regard to the integrated resource plan, we plan to file the 2016 IRP in the second half of 2016. The IRP assumes a 20-year planning horizon, with an action plan for the period 2017 through 2021. The plan will address multiple issues including replacement of our Boardman plant, which will cease operating on coal at the end of 2020, meeting the renewable portfolio standard of 20% by 2020, additional energy efficiency and demand side actions, additional capacity needs to meet our customers, and several other topics.

Now I'd like to turn the call over to Jim Lobdell, who will go into more depth on our financial and operating results for 2015, and provide the assumptions for our 2016 earnings guidance. Jim?

Thank you, Jim. Turning to slide 10, for the fourth quarter of 2015, we recorded net income of $51 million, or $0.57 per diluted share compared to net income of $43 million, or $0.55 per diluted share for the fourth quarter of 2014. This increase was primarily driven by the addition of Port Westward Unit 2 and at Tucannon River Wind Farm in customer prices, AFDC related to the construction of the Carty Generating plant, and a reduction to O&M in the fourth quarter of this year, offset by an increase in share count in 2015, related to the final draw in June under the equity forward sale agreement.

Also, targeted earnings for the fourth-quarter 2015 were reduced by warm weather, which had a negative impact of $0.05 in comparison to normal. As shown on slide 11, for the full-year 2015, we recorded net income of $172 million, or $2.04 per diluted share compared with $175 million, or $2.18 per diluted share for 2014.

This decrease was largely due to the warmest year on record in Oregon, resulting in lower residential energy sales, compounded by lower-than-planned hydro and wind conditions resulting in higher replacement power costs, and lower-than-anticipated reduction tax credits, and an increase in share count due to the timing of the final draw under the equity forward sale agreement. These decreases were partially offset by earnings from two additional generating plants placed in service -- Carty AFDC, and a strong effort to temporarily reduce O&M spending for the year.

Moving on to slide 12. For the full-year, total revenues decreased $2 million. This decrease in revenues was primarily due to a reduction in residential energy deliveries, in addition to lower wholesale and other revenues. These decreases were partially offset by a 1% increase in customer prices. Purchased power and fuel expense decreased $52 million year-over-year, driven by an 8% decline in the average variable power cost per megawatt hour. The decrease was largely driven by a 3% decrease in the average price of purchased power and the economic displacement of Boardman in 2015.

Net variable power costs, as reported for regulatory purposes, were $3 million below the baseline of the power cost adjustment mechanism. However, when adjusting for a couple of one-time transactions -- which did not flow through the Company's income statement in 2015 -- net variable power costs were $6 million above the baseline, reflecting lower wind and hydro generation, partially offset by optimization of the overall power supply portfolio. This compares to $7 million below in 2014.

Moving on to slide 13, operating and maintenance costs totaled $507 million in 2015, $23 million higher than in 2014, and $13 million below the midpoint of our original 2015 guidance range of $510 million to $530 million. The higher costs in 2015 were driven primarily by the following increases: $9 million in costs related to the addition of the Port Westward Unit 2 and Tucannon River Wind Farm, and $14 million in administrative and general costs, including $5 million increase in information technology expense, and an increase of $3 million in non-labor and outside services expense.

The reduction in O&M spending, relative to our original guidance, reflects the Company's commitment to attempt to offset reduced earnings from warm weather in the first quarter of 2015. Depreciation and amortization expense was at the midpoint of our guidance range, and increased $4 million from $301 million in 2014 to $305 million in 2015. The increase was primarily driven by a $26 million increased expense from the capital additions offset by a $22 million reduction of the amortization of deferred regulatory liability from the Trojan spent fuel settlement and tax credits, as they were refunded to customers in 2015.

Interest expense increased $18 million in 2015 compared to 2014. This was driven primarily by a $9 million increase resulting from lower allowance for borrowed funds used during construction, combined with a $7 million increase in interest expense, due to higher debt outstanding in 2015. Other income net decreased $16 million year-over-year as a result of a $16 million decrease in the allowance for equity funds used during construction, as the Tucannon River Wind Farm and Port Westward Unit 2 were put into service in December 2014.

Lastly, income taxes decreased $16 million year-over-year, largely due to a $14 million increase in production tax credits and the addition of the Tucannon River Wind Farm. The Company's effective tax rate decreased to 20.7% from 26% in 2014. We did not take bonus depreciation in 2015, and we have not taken it since 2010, because we have favored using production tax credits and other state tax credits with expiration dates over using bonus depreciation. Given the extension of the bonus depreciation through 2019, we will continue to assess our approach each year.

On to slide 14, we continue to maintain a solid balance sheet, including strong liquidity and investment-grade credit rating. As of December 31, 2015, we had $550 million in cash, available short-term credit, and a letter of credit capacity; $867 million of first mortgage bond issuance capacity, and a common equity ratio of 50.5%. The Company has a $500 million revolving credit facility to meet the Company's liquidity needs, which has a maturity date of November 2019.

The Company has additional letter of credit facilities totaling $160 million. In January of this year, PGE issued $140 million of 2.51% Series first mortgage bonds, which were used to fund an early redemption of two outstanding Series first mortgage bonds. The Company plans to potentially issue up to an additional $160 million of long-term debt in 2016.

Moving on to slide 15, on November 3, 2015, the Oregon Public Utility Commission issued an order that, when combined with customer credits, results in an overall increase in customer prices of approximately 0.7%. These prices are effective in two phases -- a 2.5% decrease in January 1, 2016, and a 3.2% increase when Carty comes into service, provided it happens by July 31, 2016.

The changing customer prices will reflect a return on equity of 9.6%; a capital structure of 50% debt and 50% equity; a cost of capital of 7.51%; a rate base of $4.4 billion; and annual revenue increase of $12 million.

As shown on slide 16, we are initiating full-year 2016 earnings guidance of $2.20 to $2.35 per diluted share. This guidance is based on warmer-than-normal weather and lower wind production in January 2016, which resulted in roughly an $0.08 impact on earnings.

Additional assumptions include the following: retail delivery growth of approximately 1% weather-adjusted, and excluding one large paper company; average hydro conditions; wind generation, based on five years of historic production or forecasted studies when historical data is available; normal tunnel plant operations; operating and maintenance costs between $515 million and $535 million; depreciation and amortization expense between $315 million and $325 million; and the Carty Generating Station in service by July 2016 at approximately the OPUC authorized capital amount of $514 million.

Back to you, Jim.

Thanks. As we begin 2016, we are moving forward on initiatives to drive value for our customers and shareholders. Slide 17 displays our key objectives for 2016.

First, maintain our high level of operational excellence with a focus on employee and public safety; meeting our operational and performance goals; and meeting our financial performance targets. Second, bring Carty Generating Station into service on or before July 31, 2016. And third, work collaboratively with all of our stakeholders to prepare our 2016 integrated resource plan, and its associated action plan, to meet our customers' future energy needs, using resources that provide the best long-term balance of cost and risk.

And now, operator, we are ready for questions.

(Operator Instructions) Michael Weinstein, UBS.

On the results for 2015, where you said that you have a temporary reduction in O&M of about $0.09, I believe you said at the beginning of the call?

Yes.

Okay. So why is that temporary? And I'm guessing that since it's temporary, that that $0.09 is now responsible for higher O&M 2016 guidance. So, going forward, in 2017, we would subtract that $0.09 out again, to normalize?

No, Michael, I wouldn't do that. What we did in 2015 was to the extent that we could push off any particular activities, and not impact safety and reliability or customer satisfaction, we took account for that. But I wouldn't add that back into the following year at this particular point in time. We still need to assess what needs to happen there.

Yes. In 2016, our O&M is aligned with what was allowed in the general rate case. And that's for work that needs to be done on our system to meet our reliability and customer service obligations. So, what we looked at in 2015 were delaying some types of work, and it's not something that we can do permanently.

Right. And also on the Carty project, is there any chance that you guys can finish the project before July right now? Or is that something you are willing to talk about in terms of -- is the project ahead of schedule? Or is it exactly on schedule? And any slippage might be a problem?

Well, we have a schedule, and it has us completing the project in July. And we have some room, but everything is going to have to go perfect. We have to go through the startup. We have to get all the construction work completed. As I mentioned earlier, we have mobilized enough people on the site to do the work. Now we have to see the productivity and we have to see everything go as we have planned.

And so we're going to watch it pretty carefully. We'll know a lot more at our next earnings call. But I would say everything is fully going at this point, and we are moving, and things are happening out at the site.

At what point do you think you will finish negotiating with the surety providers to figure out exactly how much they are going to assume?

That's going to take -- that's going to be a process. We do have a meeting scheduled in March, but that will just be the first step in the process with them.

Okay. All right. Thank you very much.

Paul Ridzon, KeyBanc.

Can you parse out the $0.08 headwind we're facing? How much of that is wind and versus weather?

Most of that is all weather. And about $0.02 of it represents wind. And then there's the PTCs in there as well, which is about $0.015.

Just back to Mike's question, so how much of the $0.09 -- well, how much was deferring versus actually just not doing? And then how much of that $0.09 is creeping into 2016?

Well, the O&M forecast that we provided the range is to do the work we need to do in 2016. Things that we didn't get done in 2015, or delayed, are basically incorporated in our budget for 2016. So, we have a budget now. We have work we have to get completed. And I think we're aligned with our budget for this year.

And that's embedded in our guidance.

Okay. And then just on the history of Carty, $514 million was approved, and now you are looking at $620 million or more. What kind of -- what's the delta there?

What's the cost? $140 million, if you took the high-end versus the $514 million? So basically what we've got there is, we have to remove liens that have been perfected associated with the site. We've got a lot of re-work that needs to be done, cost to complete the construction, which includes construction and startup, and site stabilization. There are delay costs that can include productivity, AFUDC and contingency, and other costs.

If you're successful in securing the full surety, Carty will come in under budget?

Well, I think it will come in pretty much at budget. I think the $514 million included the contractor meeting the obligations under the agreement. So, our sense would be, if the sureties do what we think they are responsible for doing, we would come in at our budget amount.

Okay. Thank you very much.

Thanks, Paul.

Chris Turnure, JPMorgan.

Could you give some more color on Carty? Just another question on that front -- how do you plan on financing the incremental cash that you are going to need to fund that this year? And have you had any conversations with the Commission yet, and kind of walking them through what's gone wrong throughout the process, to the degree that you kind of knew about it even before late December?

Well, if the first part of the question of it is how are we going to go about funding the incremental capital associated with the project, I think, as we had mentioned previously, we've got plenty of capacity under our short-term agreements, access to bank loans that we can provide in order to cover any incremental costs that we have to fund that we are not getting from the sureties associated with the project.

On the regulatory side --

Yes, I can cover that. We've been keeping the PUC informed throughout the process. We recently have been asked to provide an update on Carty through a public meeting. However, it hasn't been scheduled yet. Probably that meeting would happen sometime in March or April.

Okay. And have you disclosed how much, let's say, a one-month delay in the project past July 31st would mean for EPS?

No, we haven't.

Okay. And then my second question is just on the legislation now kind of making its way through the legislature over there. Can you give me some color on what you think the chances of passage are? And then what that would mean for the next, let's say, five to seven years of capital deployment and renewable growth opportunities for you guys? Because certainly, in the long-term, it would be a big benefit, but I'm focused a little bit more on the near-term.

Yes. So let me give you an update on it. It's called the Oregon Clean Electricity Plan. It's called HB-4036, is the actual bill number. It just passed out of the House Energy and Environmental Committee on a 6 - 4 vote. It will now go to the floor for a vote at the House level. Assuming if it passes there, then it would move to the Senate Committee, and then work its way through the Senate.

The bill essentially does two major things. Number one, it eliminates coal in Oregon by 2030. And for us, up to five years later, for coal strip up to 2035. And then it increases our renewal portfolio standard targets, mostly in the out-years. So, it's a 50% standard by 2040. The interim targets are 27% in 2025 versus the current RPS standard of 25%; 35% by 2030; 45% by 2035; and 50% by 2040.

So you can see from those new numbers the bulk of the changes would be in the outer-years as we go to a 50% RPS standard. This will all be factored into our integrated resource plan as we work through the process in this case, because we wouldn't want to go long generation as we think about a higher RPS standard.

So it's all being factored into our planning at this point, but it is all dependent on that law passing the legislature and signed by the Governor. So that's kind of where it is. We've got support -- a number of people are supporting the measure, and there's some opposition to the measure. So, we'll just have to see how it plays out.

Great. That's helpful. Thanks.

Brian Russo, Ladenburg Thalmann.

Could you just remind us the amount of capacity you need to meet the 20% RPS in 2020, and any backup capacity necessary? And then the number of megawatts you need to replace on Boardman?

So, in 2020, the RPS standard goes another 5%. It's probably very similar to Tucannon River Wind Farm -- it's probably around 100 average megawatts. So it would be very similar to adding another Tucannon River Wind Farm, if you are thinking about the size of that -- that was about 267 megawatts of nameplate capacity. So a lot of it will depend on capacity factors. So that's kind of what we're looking at.

The timing of that is still kind of up in the air. With the extension of the PTCs, we will have to evaluate when is the right timing for that unit. Because we do have renewable energy credits that we can apply. And so we're looking at what's the right timing of that, especially given the extension of the production tax credit. That will all be a topic of our integrated resource planning discussions.

As it relates to Boardman, our piece of the capacity is about 520 megawatts. Idaho Power owns 10% of the project. And so, that is again being evaluated on what the -- how we replace Boardman in the IRP. Obviously, I think prior to HB-4036, I think our thinking was likely a natural gas-fired plant would be the type of thing we would do. And we would have to do an RFP, like we did before, but, as you know, we've said before, Carty is being designed as a two-unit site. So it would be a very good site to look at a second unit there.

But with the 50% RPS standard, we have to kind of consider the entire mix and the long-term trajectory, and what's the right kinds of resources we're going to need? So it's not clear to me at this point what we will do to replace Boardman, whether it will be more capacity in renewables or baseload gas generation. So that really is the topic of the IRP. And we are just now in the process of developing portfolios that we can look at to see what provides the best balance of cost and risk going forward.

And would you need backup power for the -- and an additional windfarm?

Yes. As we look at the renewables, as you know, they are not firm energy. At least we haven't found any at this point that really correlate directly with our loads. So it would be a windfarm backed up by some type of capacity resource -- either simple cycle turbines or reciprocating engines, like Port Westwood Unit 2.

Again, we have capacity needs -- that's something that's been identified in the integrated resource plan as we look at what our loss of load probability studies show us. And so that is going to have to be addressed also. But our sense is we are going to need additional capacity as we go to a higher RPS standard.

Okay. So just back-of-the-envelope, a low $100 of KW for CCGT and maybe 1,500 of KW for wind -- and now you are talking probably $1 billion of potential spend? Is that reasonable?

Potentially. Again, as you know, we have to go through an RFP. We have to ensure that we have the least-cost, lowest-risk projects to bring forward. As we've said before, we would always want to include our own self-build options. And I think we've demonstrated, from the construction of Port Westwood Unit 2 and Tucannon that we can deliver those projects on time and on budget.

So we will want to provide our own projects. We have some sites that are very competitive sites, at least on the gas side. And we will continue to look for those windfarms or wind projects that can meet our renewable standard.

And when would you expect to get acknowledgment from the OPUC? And when would the RFP process start and then finish?

Probably in 2017, we expect the acknowledgment from the Commission.

We'll file in the latter part of this year. We would expect a Commission decision in the early part of 2017. Then we would go into an RFP process, where hopefully we would know the decision by late 2018, and then move forward from there.

Okay. Great. And then, what are the regulatory options for recovery of the Carty costs above what's in the general rate case?

Well, there's a couple of things. First of all, it depends on what the number is, obviously. If we're above that, but only slightly, we will evaluate that, and we will have to understand the reasons for that. But the way we would do that is through a general rate case.

And the next subsequent rate case -- at this point, we are not planning on filing a 2017 general rate case; looking to 2018 as a potential. We would then file that case with what we think are prudent capital costs, and we would go through the process to support those costs.

If the project is delayed beyond July 31, we will enter into discussions with the stakeholder groups to talk about options to recover the cost. A lot of it will depend on when that project will be going online, and we'll determine what's the best way to move that forward. We have options and -- but a lot of it depends on when that project would come online.

Okay. And I assume the midpoint of your guidance assumes a zero balance on the PCAM?

Yes.

And when was the net variable costs set, in terms of oil/gas prices or prevailing commodity price?

It's set in November when we file our final update, which includes cost curves and all our contracts that we have in place. Usually we're about 95% hedged against our forward position. So, we've locked in those financial or physical contracts on gas, as well as any electric purchase contracts. So we are pretty balanced in November. So then the variabilities we deal with are hydro, wind, and plant availability. So, those are things that we deal.

The good news is that hydro is about normal this year. We've had a really good snowpack early on. We'll have to see how it goes for the rest of the year, because that normal forecast does assume normal precipitation for the rest of the cycle. So, we'll watch that pretty carefully as we see snowpack build, hopefully.

And what appears to be lower gas prices now versus, I guess, what was implied in November, are you able to optimize your generation fleet to kind of capture that spread, so to speak?

Not necessarily. A lot of it will depend on what happens in the markets in terms of opportunity. But our plants are committed to meet our retail load. And so we've already locked in essentially the gas price for those plants to run and meet our retail load. There may be some opportunity, but probably the only real value is that, if, for example, we have lower wind, lower gas prices would lower our replacement costs. And similarly with hydro.

But on the flipside, if we have a lot of hydro, low gas prices depress the market price, so we don't get as much value. So it has kind of pluses and minuses as we think about it. But right now we're hedged against where our loads and resources are.

Okay. Thank you.

Michael Lapides, Goldman Sachs.

Congrats on a good year and a good start to 2016. Just curious -- thinking about the RFP process and thinking about the IRP as well. Does the state of Oregon need capacity in energy? Or does simply your service territory does? And so one of the alternatives in all of this process could be simply increasing the amount of power that could be sent into the Greater Portland area from other parts of the state?

The reason that's -- I'm kind of thinking through that is, there are -- we've seen in other states over the years -- Louisiana and Mississippi are a great example of this, also in the desert Southwest, where merchant projects that were in a state, like an Oregon or like a Louisiana or Arizona, wound up getting bid into RFPs and sold at a price that was well below newbuild cost.

Now some of the ones in your state, they are not really in downtown Portland, so there would have to be a transmission alternative. But I think that largely will depend on, is it a state need? Or is it part of the state need for new capacity in energy?

So let me talk about that generally. In the last IRP, projects that were available were bid in, and they were not competitive with new generation, just because of higher heat rates and older units. So they were not successful. And to that extent, nothing has built since then, to my knowledge, in the region, in terms of new gas-fired generation.

And then on top of that, you've got several plants that will be taken out of the regional mix -- like the Centrelli -- or the -- yes, the Centrelli plants will be going away. Boardman will be going away in 2020. And what has been added to the marketplace has been mostly variable energy resources --

Under contract.

Yes.

Typically under contract. So you think about Oregon and maybe the region, I see us being more capacity-deficit. Our studies show that. And there's just not capacity sitting on the sideline. On an energy basis, it's a really kind of a tough issue as we see all these renewables show up in the system. Obviously what's going on in California with the debt curve and all the solar energy down there, those are things we are looking at.

But the straw into California is only so large. And so we have to think about the reliability of that supply as well as the cost. So those are things that we are evaluating in the IRP. But I would clearly say there is a need for additional capacity in the region, especially as we add more variable resources.

Got it, guys. Thanks. One follow-up unrelated to that. You made some minor changes to your base CapEx forecast in today's disclosure. Can you just kind of walk us through what drove those changes?

Yes. Effectively, it was just a shifting of dollars associated with our customer information and meter data management project. And that was essentially it.

Meaning moving stuff into 2016 from --? Can you just like -- which years went up? Which years went down? And what was the -- and was that the main driver of that when I think about 2016, 2017, 2018 or so?

It was the movement of dollars from 2017 to 2016.

Got it. Okay. So you just moved up the project a little bit?

Yes.

Got it. Thanks, guys. Much appreciated.

Thanks, Mike.

(Operator Instructions) Paul Patterson, Glenrock.

Just on HB-4036, it looks quite ambitious. And I haven't checked; when it passed -- I guess it was, what, yesterday? -- did it -- were there any amendments that addressed some of the issues, I guess, were being brought up by the Oregon PUC? How -- I guess, was there any big changes? Or were those issues addressed? Or do you think that -- I mean, it looked like it passed with a pretty good margin. I mean, I'm just sort of wondering.

Yes, it passed 6 - 4. I don't recall if there's -- I was talking to Dave yesterday; there weren't any major amendments. There might have been a few tweaks but nothing that was material to the way the legislation was set up.

I think the important thing to note is it does still have the cost cap that's currently in the legislation today. It also has added another standard around reliability. So it has provided certain protections for our consumers that we think are adequate to address the concerns the Commission has raised.

Our evaluation looking at price impacts on consumers over the lifecycle of this bill, is somewhere in the 1.5% higher prices. So it's not materially higher. As I said, the bill has passed the House Committee. It's going to the House floor for a vote. It can then move to the Senate, where we could see potential other amendments. And we'll have to see how that plays out in the coming weeks.

It looks like it's on schedule for the House passage next week -- early next week --?

That's correct. And then it goes to the Senate; Senate Business and Transportation Committee.

Okay. And is energy efficiency part of the RPS standard? Or is that separate? If you follow what I'm saying. In other words, I mean, does energy -- because I did notice this regional for state thing that was big pushing energy efficiency. Is that part of getting to the standard --?

No, because that just reduces our load. Energy efficiency is just the measures that -- we don't want to continue our commitment to energy efficiency, we use the Energy Trust of Oregon to determine what is the least-cost, lowest-risk energy efficiency and how to acquire that. We do a very detailed study in our IRP to determine what that is.

And so I don't think that changes dramatically in this legislation. It just continues to support the need for energy efficiency. But it does not count against the RPS standard in the sense that it's part of the -- how we meet retail load. It would reduce retail load, but it doesn't necessarily count against the percentages.

Okay. Excellent. And then just in terms of obviously this CapEx forecast, we should expect that, once we get more information on HB-4036 in your IRP, that those numbers will probably be conservatively higher, I would expect; correct?

Yes, I think the question we have to ask -- and we'll be looking at this in the IRP -- is, given the shutdown of Boardman and its high RPS standard, what's the right timing and quantity of renewables we need to add to the grid, kind of to get us to the 50%?

Because you wouldn't want to necessarily add just baseload gas generation, and then find out that you have too much generation as you go to a 50% RPS. So we're going to have to think very smartly about the right mix of resources and the trajectory to get to that 50% RPS. And the bill does allow us to maybe pre-build ahead of the need, if we can demonstrate that's the cost-effective thing to do. So that's really the magic here in trying to figure this all out, is what's the right timing of doing this in a way that provides the least-cost, lowest-risk for our customers?

Okay, great. The rest of my questions have been answered. Thanks so much.

Thank you.

Michael Weinstein, UBS.

A quick follow-up question. On the legislation, as a co-owner of coal strip 3 and 4, just wondering what do you see -- how do you anticipate the disposition of that plant? Once coal by wire is eliminated in 2035 or under the legislation, what do you see happening with it?

So -- and we've thought a lot about that. Obviously, our plan under this would be to recover all the capital costs and decommissioning costs through 2030 or 2035, depending on -- the legislation allows us to keep the plan in customer prices through 2035.

So, beyond that, the question is, what would we do with the plant? There's options we would consider. Obviously, if the plant continues to operate, it has value. We could either sell it in auction; we could sell the power in the market. Those are two considerations as we look forward. And those are things we will have to evaluate as we get closer to that period. And so, we don't have an answer yet but we have options.

We're minority owners.

Yes. We're a 20% owner in 3 and 4, so it's not like we can decide to shut the project down. And so we will look at that as we get close to that timeframe, but those are the two options we would consider.

Okay. I'm just wondering if there's been any moves to try to push to sell to Puget Sound there, just like they are doing with coal strip 1 and 2 --?

Well, yes, I understand that. And, in Washington, they have a prohibition from utilities buying coal output also. So, I know they are working on their own issues around units 1, 2, 3, and 4. And I -- you'll have a lot to see when we get there. I think the landscape could change. Montana is a potential market. Obviously, there are other places that that power could be sourced to.

Yes. Yes.

All right. Okay, thank you.

Felix Carmen, Visium.

Just a question on slide 14 regarding the financing. You guys have earmarked about $160 million of additional bonds you may issue. Is that currently embedded in the future tests here that you have this year and in guidance? What's the situation with the interest related to that? And what would decide if you issue it or not?

Yes. No, it is included in the guidance already.

And is it included in the rate case?

It's not included in the rate case.

Because I think we do -- we update the numbers for those bonds or --?

We updated for the bonds in --?

January.

In January, yes, okay. Everything is aligned up with the guidance that we have.

And then just one follow-up question -- I know this is kind of an asset. I just want to make sure I understand it correctly. On the surety bonds, by when do you need to have some kind of resolution on those before you decide to take action at the Commission? I mean you can have the plants in service by your required service date, but when do you need to know about the recovery of the surety bonds before you go to the Commission?

Well, right now, our prices are based on the $514 million, and that's kind of the agreement we have. The next time we would address this as a subsequent general rate case. And so we would obviously need to have that resolved by then. But if we're looking at a 2018 general rate case, we've got sufficient time to address that. Again, our hope is that we would get full compensation for the exceeding -- the cost exceedance, but that's obviously something we have to work through with the sureties.

Okay. Appreciate it. Thank you. And congratulations.

Michael Lapides, Goldman Sachs.

Just a quick question on rate case timing again -- meaning going forward. It doesn't sound like you are going to do a lot of construction on stuff related to the RFO or RFP until the 2019 timeframe. Do you anticipate filing again between now and then?

Yes, right now our thinking is 2018 general rate case, but a lot of that will depend on load growth, inflation, cost controls -- just a number of factors that we look at. We clearly have not filed for a 2017 rate case and don't anticipate doing that, absent something going on with Carty.

So we would likely look at 2018 -- we won't make that decision until probably November of this year when we finish our budgets we file in February of 2017 for a 2018 general rate case, if we decided to do that. But it will also depend on interest rate, what return on equities are doing. So a whole bunch of factors will go into that decision. But right now, that's kind of what we're pointing towards, but we haven't made a good final decision.

Got it. So you would file in 2017 for 2018, but that really wouldn't incorporate many of the stuff coming out of the RFP process?

Not at this point, no. And to the extent there are renewable resources, we do have the tracking mechanism under the current RPS standard, that those can get tracked in directly when they go into service. So it would only be either capacity resources or something -- other type of thermal resources that would have to get -- would require a general rate case. So we could actually track in the renewables with the current standard we have and the mechanism we have.

Got it, guys. Thank you. Much appreciated.

Thank you.

Thank you.

Okay. I think that's the end of the calls. We appreciate your interest in Portland General Electric, and invite you to join us when we report our first-quarter 2016 results in late April. Thanks again and have a great day.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Have a great day, everyone.