Portland General Electric Company (POR) Q1 2017 Earnings Report, Transcript and Summary

Good morning everyone and welcome to Portland General Electric Company’s First Quarter 2017 Earnings Results Conference Call. Today is Friday, April 28, 2017. 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 will turn the conference call over to Portland General Electric’s Manager of Investor Relations and Corporate Finance, Chris Liddle. Please go ahead.

Thank you, Amanda. Good morning, everyone. I’m pleased that you’re able to join us today. Before we begin our discussion this morning, I’d like to remind you that we have prepared a presentation to supplement our discussion, which we will be referencing throughout the call. Those slides are available on our website at investors.portlandgeneral.com. Referring to Slide 2, I'd like to make our customary statements regarding Portland General Electric’s written and oral disclosures. There will be statements in this call that are not based on historical facts 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 forward-looking statements made today. For a description of some 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-Q. Portland General Electric’s first quarter earnings were released via earnings press release and the Form 10-Q before the market opened today, both of which are available at investors.portlandgeneral.com. The company undertakes no obligation to update publicly any forward-looking statements whether as a result of new information, future events or otherwise. This Safe Harbor statement should be incorporated as part of any transcript of this call. Leading our discussion today are Jim Piro, President and CEO; and Jim Lobdell, Senior Vice President of Finance, CFO and Treasurer. Following their prepared remarks, we will open the lines for your questions. Now, it’s my pleasure to turn the call over to Jim Piro.

Thank you, Chris. Good morning, everyone and thank you for joining us. Welcome to Portland General Electric's first quarter earnings results. On today's call, I'll provide an update on our financial and operating performance, the economy in our operating area, our capital expenditure forecast through 2021, an update on our Carty Generating Station litigation, our 2016 integrated resource plan and finally the status of our 2018 general rate case. Turn I'll turn the call over to Jim Lobdell who will provide more details on our financial performance and guidance. As presented on Slide 4, we reported net income of $73 million or $0.82 per diluted share in the first quarter of 2017, compared with net income of $61 million or $0.68 per diluted share in the first quarter of 2016. Higher net income was primarily related to increased energy deliveries in our service area, resulting from one of the coldest winter seasons we've seen since 1979. Additionally, we had strong industrial demand from the high-tech sector, offset by storm damage and lower wind generation. On Wednesday, the PGE Board approved our 11th consecutive annual dividend increase since we went public. The 6% or $0.80 per share annual increase reflects our commitment to providing a competitive return for investors and it is driven by the company's ability to execute our long-term strategic plan of operational excellence, business growth and corporate responsibility. Moving to Slide 5, I am pleased report the company's strong operational performance during the quarter of historic snow, ice and rain. It is a testament to our employee's commitment to delivering safe and reliable service to our customers, regardless of the elements we face. In addition, during the quarter our generating plants achieved a 95% availability. I am also proud to share that PGE continues to be ranked in the top quartile for customer satisfaction for residential, business and key customers according to Market Strategies International and TQS Research. Additionally, we were again named 2017 Environmental Champion by our customers, according to a nationwide survey of utility customers connected by Market Strategies International. Not let's move to Slide 6 for an update on the economy and our customers. We continue to see positive economic trends in our service area, including employment that's the lowest on record in Oregon. Wages that are rising at a healthy pace and a year-over-year 12% increase in building permits. The Oregon Office of Economic Analysis is forecasting continued gains in the Oregon economy in 2017, including job growth of 2.4% and reaching more than 21,000 housing starts. In March, unemployment in our service area was 3.3%, which beats Oregon at 3.8% and the U.S. at 4.5%. These low levels have not been experienced since prerecession and indicate an economy near full employment. The continued strength of Oregon's economy contribute to an increase in PGE's total customer count of approximately 1.1% compared to the first quarter of 2016. While we experienced strong residential and industrial energy deliveries in the first quarter of 2017, we continue to expect weather adjusted energy deliveries in 2017 to decrease between 0% and 1%. This is based on expected decreases in delivery to metal manufacturing customers and ongoing energy efficiency efforts, lowering the residential and commercial low growth rate. Looking forward, we continue to forecast long-term positive annual energy delivery growth of approximately 1% based on the strength of our local economy. In particular we're forecasting growth in the high-tech sector and the continuation of strong in-migration. On Slide 7, we've provided a summary of the company's current capital expenditure forecast from 2017 through 2021. These expenditures are related to investments we're making to maintain and build a more resilient grid. Our investments include upgrading and replacing aging generation, transmission and distribution infrastructure, strengthening and safeguarding the power grid to better prepare for storms, earthquakes, cyberattack and other potential threats and implementing new customer information system and technology tools to ensure employees can continue to provide prompt, effective service to our customers. We have not including any capital expenditures related to potential projects, pursuant to our 2016 integrated resource plan. We have also not included future capital expenditures for system resilience. Moving to Slide 8, we have provided an update on the Carty Generating Station, our 440-megawatt natural gas baseload resource near Boardman, Oregon, that went into service on July 29, 2016. As of March 31, we had $636 million including AFDC of capital cost for the project. Our estimate for the final capital expenditures for Carty remain at approximately $640 million. As previously reported, we are pursuing legal actions against Liberty Mutual and Zürich North America, the two sureties who provided a performance bond in connection with the Carty construction agreement. At the end of July 2016, the US District Court of Oregon ruled against the sureties motion to stay the proceedings filed by PGE in U.S. District Court of Oregon and ruled in favor of PGE's motion to enjoin the sureties from participating in an International Chamber of Commerce arbitration proceeding initiated by Abengoa related to the parental guarantee provided by Abengoa in connection with the Carty construction agreement. The sureties appealed the District Court's ruling to the Ninth Circuit Court and on December 13, the Ninth Circuit issued an order staying the district court proceeding, pending a decision on the appeal. The oral argument regarding the appeal is scheduled for May 8 at the Ninth Circuit Court and we anticipate a decision will follow several months later. For more detail, you can refer to our 10-Q. Slide 9 provides an overview of the timeline and action plan for our 2016 integrated resource plan that we filed with the OPUC in November 2016. The action plan calls for a minimum of 135 average megawatts of cost-effective energy efficiency and 77 megawatts of demand response across the four-year planning period. Additionally, the action plan call for a 175 average megawatts of qualifying renewable resources. Our initial IRP decision -- our initial IRP submission also identified the need for us to acquire up to 850 megawatts of capacity, which included 375 megawatts to 550 megawatts of long-term dispatchable resources and up to 400 megawatts of annual capacity resources. Since our filing the 2021 capacity need in the IRP has been reduced from 819 megawatts to 561 megawatts. This is due to three key developments. One, our December 2016 load forecast update reduced the capacity need by 71 megawatts. Two, on March 29, 2017, we executed a 10-year power purchase agreement with Douglas County PUD, renewing our contract for a portion of the output of the wells hydroelectric project beginning September 01, 2018. This contract reduced our capacity needs by 135 megawatts and three, additional contracts that were executed with purpose of qualifying facilities between June 01, 2016 and December 31, 2016 that reduced our capacity need by 52 megawatts. We continue to explore opportunities to acquire additional, reliable and cost effective flexible capacity for our customers through bilateral negotiations with owners of dispatchable generation resources in the Northwest. If we are able to secure capacity to meet some or all of our needs through bilateral negotiations, we would submit such agreements to the commission for approval along with a waiver request of the commission's competitive bidding guideline as necessary. As part of the OPUC IRP public review process, we filed comments on March 31, 2017. An additional round of comments will follow in May as we address stakeholder questions and how to identify the best strategy for achieving a renewable reliable and affordable energy future for our customers. We expect the OPUC to issue a decision on our IRP on or before August 31 of this year. Following the acknowledgement of the IRP and the outcomes of bilateral negotiations for flexible capacity, we will request approval form the OPUC to issue one or more requests for proposals for remaining capacity needs and renewable resources. As I said before, we have no predetermined out-company's RFPs. We're open to a wide variety of options and we'll be seeking the best combination of resources consistent with the acknowledged IRP action plan to meet our customer's future energy and capacity needs. Resource options include, hydro, wind, solar, geothermal biomass, efficient natural gas fired facilities and energy storage. The RFP process will include oversight by an independent evaluator who reports to the OPUC and overall review by the OPUC itself. In preparing for the RFP process, we have identified a potential wind benchmark resource in Eastern Oregon with the nameplate capacity of up to approximately 500 megawatts, which would qualify for the production tax credit. The submission of this resource into an RFP is subject to additional due diligence and the negotiation and execution of a definitive agreement. Moving on to Slide 10, at the end of February PGE filed its 2018 general rate case with the Oregon Public Utility Commission. As previously discussed, the filing is based on a 2018 test year and will include investments related to keeping PGE system safe, reliable and secure. The investments include replacing asset at the end of the useful life, strengthening our system to better prepare for storms, earthquakes, cyberattacks and other potential threats as well as investment in operational changes that will integrate more renewable resources and enhance system reliability. The key items of the case are our return on equity of 9.75%, capital structure of 50% debt, 50% equity and a rate base of $4.6 billion. Regulatory review will occur throughout 2017. In early May, a key stakeholder workshop is scheduled to help answer questions before staff and intervenor testimony is filed in early June after which we'll enter into settlement discussions. PGE expects the OPUC to issue a final order by the end of 2017 with approved prices going into effect on January 01 2018. Now I would like to turn the call over to Jim Lobdell who will go to more depth on our financial and operating results, liquidity, earnings guidance and the dividend increase. Following his prepared remarks, we will open the lines for your questions. Jim?

Thank you, Jim. As Jim mentioned, for 2017 we reported net income of $73 million or $0.82 per diluted share compared with net income of $61 million or $0.68 per diluted share for 2016. Slide 11 shows a walk-through of our income statement changes year-over-year, a few things to note on this slide are, first, retail revenues increased $26 million for the quarter. This was largely the result of increased retail deliveries to an exceptionally cold winter as well as increased customer prices due to placing Carty into service, partially offset by a reduction in PGE's annual update tariff. Second, a $5 million decrease in power costs as a result of an average decline in the price of purchased power, but was partially offset with an increase in system load and a 17% reduction in wind generation. Third, generation, transmission and distribution costs increased by $9 million due to major storm restoration efforts, Carty related operating expenses and a legacy tool replacement project. Four, administrative and general expenses increased by $4 million due to approximately $1 million of Carty litigation expenses and $1 million related to increase employee benefit expenses and $2 million and other miscellaneous expense. And finally, an increase in other miscellaneous items such as depreciation and amortization expense due to Carty being placed in service in July 2016 and increased IT hardware and software purchases, partially offset by the Trojan spent fuel amortization. We also have increased property taxes due to increased Oregon property valuations as well as a decrease in AFDC equity due to lower balance. On to Slide 12, which shows earnings drivers for the quarter, first gross margin increased earnings by $0.22 due to the following. A $0.27 increase due to higher retail deliveries as a result of colder temperatures, an $0.08 decrease due to lower weather adjusted energy deliveries driven by a leap day in 2016 and lower commercial deliveries in 2017 as a result of storm-related closures partially offset by the decoupling. A $0.03 increase due to lower power prices as a result of favorable hydro conditions in the region, partially offset by decreased wind production. The next driver is a $0.05 decrease related to distribution cost, resulting from a $0.03 decrease due to major storm restoration costs and a $0.02 decrease for the replacement of large legacy hand tools with ergonomic battery power operating tools. The third driver is a $0.02 decrease related to Carty. $0.01 for depreciation and carrying cost of Carty's capital spending greater than the $514 million in customer prices and $0.01 for litigation costs. Finally, a decrease in production tax credits due to lower wind production resulted in a $0.01 decrease to earnings per share. On to Slide 13, we continue to maintain a solid balance sheet including strong liquidity and investment grade credit ratings. As of March 31, 2017 we had $635 million in cash available short-term credit and letter of credit capacity, $1.2 billion of first mortgage bond issuance capacity and a common equity ratio of 49.8%. The company has a $500 million revolving credit facility to meet the company's liquidity needs, which has a maturity date of November 2020, an additional letter of credit facilities totaling $160 million. In 2017 PGE plans to issue up to $450 million of first mortgage bonds a portion of which will replace $150 million of bank loans maturing in November 2017 with a balance supporting capital expenditures. As shown on Slide 14, we are reaffirming full year 2017 earnings guidance of $2.20 to $2.35 per diluted share. Guidance is based on the following assumptions. A decline in retail deliveries between 0% and 1% weather adjusted, above-average hydro conditions based on the current year hydro forecast, wind generation for the remainder of the year based on five years of historic levels or forecast studies when historical data is not available, normal thermal plant operations for the remainder of the year, depreciation and amortization expense between $340 million and $350 million, revised operating and maintenance costs from $540 million to $560 million to $550 million to $570 million, driven by 11 million of major storm restoration costs, including the April windstorm of which $2 million is offset in revenue by existing major storm recovery. In January, PGE filed for deferral of major storm costs above the $2 million of existing recovery. No action has been taken on this filing we have not recorded the deferral. More details will become available on the OPUC website under Docket UM 1817. Additionally, we expect to incur a higher Carty litigation costs and now our full-year forecast for Carty-related incremental charges is $0.09. Turning to Slide 15, regarding the company's quarterly dividend on April 26, the Board of Directors completed its annual dividend policy review and approved an increase of 6% for a new annualized dividend of $1.36 per share on the $0.34 for the quarter. The comparison to our prior annualized dividend of $1.28 per share or $0.32 per quarter. This increase represents a payout ratio of 60%, based on the midpoint of our 2017 earnings guidance. Assuming PGE's ability to achieve current estimates for earnings and cash flow and depending on other factors influencing the dividend decisions, PGE's management continues to anticipate sustainable annual dividend increases of 5% to 7%. Over the long-term PGE targets a dividend payout ratio of approximately 50% to 70%. Back to you Jim.

Thank you. Moving to Slide 16, in summary we continue to focus on successful execution of initiatives that drive value for our customers, our community and our shareholders, including maintaining our high level of operational excellence with a continued focus on employ and public safety and meeting our operational and financial goals, working collaboratively with all of our stakeholders to obtain acknowledgment of our 2016 integrated resource plan and an associated action plan to meet our customer's future energy needs and finally achieving a fair and reasonable result in our 2018 general rate case. Now operator, we're ready for questions.

Thank you. [Operator instructions] Our first question is from the line of Julien Dumoulin-Smith from UBS. Your line is open.

Hi. Good morning.

Hi.

So, I wanted to clarify a couple of comments and perhaps just understand a little bit where you stand around the load growth and specifically looking a little bit more forward on the need projected in the IRP. Obviously, you've identified three factors reducing the projected need in the updated IRP, but can you discuss a little bit more about continuing to explore opportunities to acquire additional resources through bilateral negotiations? I thought that was what you've already reflected here with Douglas County PUD for instance. Are there more and just how many more of those kinds of resources are options out there, if you can just elaborate a bit?

So, I'll have Jim address the load forecast change in a minute, but let me talk a little bit about bilateral negotiations. We are looking at, there is a number of resources in the Northwest and loads of across the overall Northwest have been down as a result of some closures of aluminum smelters in the region. So I think we are looking at those existing resources to see if there is the opportunity to enter into an agreement to enter into a contract or to acquire an asset that could meet our capacity needs at a lower cost than building Carty 2 or 3. We continue to permit Carty 2 and 3, but we have an obligation to always look at the least cost, lowest risk option and we are pursuing those bilateral negotiations discussions to see if there is a lower cost option to meet 560 megawatts of capacity shortfall that we have in 2021. So, we're entertaining those conversations, we believe that bilateral negotiations are the best way to do that to the extent we can identify parties who are willing to enter into cost effective agreements, we will pursue those, but we continue to hold Carty out there as a backstop to ensure that we have competitive alternatives. And so that's the process we're in right now. We hope to conclude that within the next two to four months to determine whether those are available. We will then inform the commission of whatever we find in those bilateral negotiations. So just we want to be sure we pursue all opportunities and make sure that we identify the least cost lowest risk before we entertain asset types of -- new asset types of acquisitions. Hopefully that's helpful.

Jim on the load side effectively it's just some of the trends that we've seen out there, we're still expecting a lot of growth in the large industrial side that as we pointed out before we're seeing just a little bit of a slowing trend there. We've had loss of that large paper company in the past and just some continued operational changes on the metals and solar manufacturing side. And then we've got the potential still out there associated with the long-term direct access.

Excellent, can I follow-up on the RFP again in the context of the wind, you say a wind benchmark resource, is this effectively to be interpreted as something that you would be bidding into the RFP with this potential partner as something of a building transfer. I just want to understand the term, the Benchmark Resource Certificate.

First of all, just to get clarity around the renewable RFP, that is predicated on the decision from the commission that we should move forward with the physical resource. We do have existing renewable energy credits on our books that could carry us for a period of time, but we believe because of the value of the production tax credit, it makes sense to acquire a resource now to take advantage of that 100% or 80% production tax credit before it goes to zero. So, to that commission agrees that we need to acquire physical assets with those kinds of characteristics, we would issue an RFP. Within that RFP we would file a Benchmark Resource that we described in our comments today as a benchmark that we could potentially -- that if they were to win in the RFP, we can execute against, it would be an ownership option for the company.

Got it. And you just described this as being eligible for ITC, is that at the full 100% or is that at the reduced 80% level for the Benchmark Resource?

It's PTCs and it really depends on how quickly we can move through the RFP and start construction. It's critical that that project goes online by 2020 is it, by the end of 2020. It 100% eligible but it has to be completed by the end of 2020 I believe to get the 100%. If not then it would be 2021 and they would qualify for 80%. So, I think that's why we're trying to move as quickly as we can to capture that value for our customers, but production tax credit is pretty valuable in terms of reducing the overall cost for our consumers.

Got it. So, to be clear by this, it's already qualified for the 100% PTC with the notable risk that if the product isn’t completed by 2020, given the timeline of the IRP and subsequently RFP, that would be the risk in which we would drop down?

You got it.

Excellent and under the current timeline, I know you're cautioning this, you would presumably be moving into awarding the RFP when it sounds right now just to be clear about that?

Probably midyear 2018 just depending on how quickly we can move through the process, but we would like to do it sooner obviously because that would put us in a better position. But we have to get the order from the commission this year and then we have to get the RFP approved and then we have to go through the RFP process. So, I think we're targeting midyear next year, which we still believe is sufficient time to get a project completed by the end of 2020.

Excellent. Thank you, all.

Thank you. Great questions.

Thank you. And our next question comes from the line of Brian Russo of Ladenburg Thalmann. Your line is open.

Hi. Good morning,

Good morning, Brian.

Could you just tell us what -- where you are in the on the PKM or the dollar amount above or below the baseline.

We're $2 million below the PKM right now, the baseline.

Okay. And then just to clarify on guidance, you're assuming above normal hydro conditions, is that the year-to-date actual or is that the forecasted April to September Hydro season?

That's taking into account what we've seen already for the first quarter and if you look at the basins that we pull out of whether it be the Grand Coolie at the top end of the system, that Dallas at the bottom, the shoots, the Clackamas River or the other sub basins that we pull water out of. Everything this year is over 100% especially the mid-Columbia's up around 123% here at the top end of the system. So, it's all looking pretty good and if Mother Nature is on this call just tell her we're done. We don't need any more rain. We don't any need any more stuff.

If you're on the big question Brian is how does it come off? Right now, it's been relatively cold. In fact, we're still seeing snow as of last couple of days up in the mountains. So, the real question is how did they come off and how does that affect the overall region. You're obviously where California is got a wash of Hydro. So, the longer it stays colder, the slower the runoff, the more value it provides for us. We get an exceptionally warm May and it still comes off quickly than you always have the potential and also because we tend to see high wind, high water together, the value of that hydro gets diminished. So clearly, we like to see it kind of stay cold and let that run off come off slowly. So, we see it in July and August which provide much more value to us in terms of reduced our power cost.

Right. Understood, so to be clear, the guidance reflects the NOA water supply forecast for the current season.

Yes.

Okay. Got it. And then I'm just curious hypothetically speaking if you win the litigation versus the sureties what's the financial impact you just take kind of a one-time gain, I am just curious in anticipation of what that might be?

No, we would reduce it against planned service because the $640 call it is higher than what we have allowed in customer prices which I think is 514, we would just reduce the CapEx by that amount. So, there would be some income statement effects for the amount of depreciation we run through the income statement and maybe for litigation expenses and maybe some of our cost -- carrying cost, but that will all be kind of worked out when we get the final settlement and depending on the amount. But to the extent we are allowed to, we believe we have the right to recover some of our litigation cost and that would help, that would go to the income statement since we're absorbing that today.

Okay. And then lastly, just can you update us on the proposed legislation regarding, well I think dive one that is ongoing?

Right. Those are the two bills that I think were proposed in the legislative session. Both have been pulled back and they’ve been transitioned to a steady build, to a bill called 978, which is a steady bill now, which directs the OPUC to investigate these issues that were raised. 979 is dead and 978 essentially converted into a steady bill. And that is still the rules committee and it still has not been approved, but that's kind of direction they're going. So, the PUC would conduct a study on all these issues and they will report back to the legislature if necessary, but…

Do they come back in September of 2018?

Yes, and if the bill is approved.

Okay. Got it. Thank you.

Thanks Brian.

Thank you. Our next question is from the line of Siddharth Verma of Goldman Sachs. Your line is open.

Hi a quick question. Do you see the IRP process as delayed and how should investors think about what this means for the timeline of building new gas or plants?

So, we did delay the IRP a bit a time. So, we can respond to all the comments raised. In terms of building a gas plant as I mentioned earlier, we're going to pursue bilateral negotiations first to see if there are any existing resources out there that we could contract for that could fill that capacity need of 560 megawatts. If we're unsuccessful there than, we would issue an RFP for capacity Carty 2 and 3 are still backstopped. They would be potential self-build options but probably would be bid in like we did with Carty 1, which allowed the site to be bid in, by the contractor, but it would be bid against the other options in the market. So, I think the first thing for us to do is complete the bilateral negotiations, see if there are any contractor or agreement that we could enter into that are lower cost or in the alternative we would then go to the RFP process. So, we continue to cite those projects. They are kind of a backstop at this point, but the viable options, the site is permitted in terms of the size of the site to be able to accommodate these units, we do have to get the permits of the projects and we're right now in the permitting process.

Got it. Thank you.

Thank you. And our next question is from the line of Travis Miller of MorningStar, your line is open.

Good morning Thank you. At a higher level maybe long-term strategic type question, I've been hearing from some utilities out your way that natural gas pipeline midstream is actually becoming more of a constraint than finding electric capacity transmission generation, is that true from your view? What are you saying in that natural gas midstream the ability to get that gas reliably, some thoughts around that. And then and out-of-the-box slot, would you ever consider putting midstream gas into a rate base type structure going into that?

That's great question. The first question I would say is as for our existing resources we have adequate transportation capacity for gas to our resources and as you know we are in the process of completing with Northwest Natural Gas a storage option called Emerald that would provide storage to our Beaver-Port Westward site. So at least where we are today, we're in good shape on gas transportation. As we look longer-term, the main pipelines probably have adequate capacity. The question is the gathering facilities up in Canada and in ultimately gathering facilities in the Rockies. So those are things we're looking at and always evaluating and we'll have to consider as we look at the capacity kinds of resources we have. But we're setting those options, as to your question of whether we would put gas transportation assets into rate base? I think that really depends in terms of how that goes forward. We believe the gas transportation companies are the best people to provide that service, but as you know at the end of the day, we're going to contract with that capacity and so depending on our relationship with their gap pipelines, we might consider that. It would have to be totally aligned with our existing rate base asset on an asset that we needed to provide service to customers because either way we're paying for. We've paid it abated through a contract tariff rate or we would have it in rate base and look virtually the same. But typically, we've relied on the transportation the transport companies to provide that service, they’re best suited to do. They understand the rules of the road, but I would say we do have one small gas pipeline that we do own it's called KB Pipeline that provides gas transportation service to our Port Westward site. So, lateral small lines that connect the mainline might be a place we would play, but major lines probably not.

Okay. And then you do have the capacity in IRP lengths of time and the foreseeable future there is plenty of capacity there.

For our existing assets yes, as we look at future assets, we would then have to acquire and lock in those transportation assets to be able to fuel those resources. So, we're not going to acquire ahead of time, but we would clearly have that as an important part of the RFP process to be able to demonstrate your firm transportation capacity to be able to fuel the resources.

Okay. Great. I appreciate the thoughts.

Thank you.

Thank Travis.

Thank you. And our next question is coming from the line of Paul Ridzon of KeyBanc. Your line is open.

On the bilateral contracts, are you looking at certainly PPAs or actually buying physical assets of the rate base?

Both.

Okay. And then you referenced wind farm that you bid into the RFP, how do you feel about competitiveness of that from an economic standpoint?

We'll find out in the RFP, but we believe it's a well-positioned asset, but at the end of the day it is a RFP process.

What's the status of that? Is it just someone’s kind of done some project development and you're going to be buying the project sometime or how far along is the actual project?

We really can't talk about, that's under confidential negotiations at this point.

Understood. Thank you very much.

Thank you.

Thank you. And the next question is coming from the line of Andy Levi of Avon Capital Advisors. Your line is open.

Hi Andy.

Just real quickly on the potential acquisition of a resource how does the regulatory process on the work if you were to go down that road?

So, the way it works right now, if a contract is five years in duration or greater than 100 megawatt and we haven’t gone through a competitive bidding process, we believe we have to get approval, a waiver from the commission on not using the competitive bidding process. This is being done by other utilities before. So, there is the process to do that. That would help us get certainty that the regulators believe what they’ve done is included. But ultimately, they have to make that decision in a rate case. So that kind of a standard we work under. We have informed the commission staff of this idea and many of the parties are very supportive of doing that first to ensure that we've looked into the market to see if there is more cost-effective alternatives. So that's the process we would go through. Jim, do you anything to add to that?

No.

Is that for the acquisition of an asset or did you approach this power agreement or both?

Both, even lines.

Okay. And are you currently I guess shopping around, is that a good way to put it for an asset right now?

We are talking the parties in the Northwest and all the parties who have we believe resources that would get our needs.

Okay. So, if you were to -- I guess you have to get through the IRP process first, right before you would you transact, is that correct or not?

No, that's not correct. If we can identify what we believe are competitive alternatives, that would be what we think are priced at a very favorable point, we would go ahead and enter into those agreements and then take them to the PUC for approval and waiver of the competitive bidding rules.

So just on the acquisition aspect which would obviously go to rate base, that I assume any type of deal that you would make would be contingent on regulatory approvals that kind of way to think about it.

Yes, they don't give us the waiver then effectively then we can't enter into them and so they would have conditions precedent in neither agreement that we would have to get commissioned approved or waiver of the competitive bidding guideline.

And then how it will work? Let's say you ended up announcing something this year of acquisition of XYZ asset doesn’t matter for how much its for and then but the resources needed until 2020, I would think that the person entity selling it would probably want to close before 2020 maybe not. How would that work? Would it go in the rate base sooner and would you change another resource or how would that basically work?

That's all part of the conversation we're having with the parties out there. Clearly, we like the time with our need, but that's all part of the negotiation what their needs are and what our needs are and then how does that affect the economics.

And also, whether the asset is encumbered by other contracts, purchase power agreements.

Okay. So, I guess the various different ways it could work out, but again if you were to acquire asset and depending on I guess on the contracts on it, but let's just go down the road that it actually gets approved, it could go into rate base sooner than the resource was identified to be needed or it could go when it was supposed to but it is possible depending on the situation that it could go in '18 or '19 versus going in at '20 or '21, is that correct?

It could, based on the economics and the case we make. I think clearly, we have to take that through a general rate case because renewable -- because renewable have a way to track it in but new kinds of gas fired resources or capacity things would have ownership options would have to go through a rate case. If it was a PPA, then it would go through our power cost immediately through our AUT filing, but again, we have to be able to demonstrate that early acquisition made sense for our customers. So, I think the best time it would have these resources come in line in the 2020 to 2021 timeframe but that's all part of the negotiation and the opportunities that are out there.

And are there kind of several opportunities out there as far as plants that are available? I am not sure what the market is in your region?

We're talking to several parties in the Northwest.

And these are kind of newer type plants?

It could be capacity context from existing resources also.

Well I guess what I am saying is it's not a 20-year old plan. It's something that's stated -- somewhat state-of-the-art I would guess right because this would if you were to buying it would be more of a longer-term type of commitment, right?

Andy we're looking at all the resources that are out there in the marketplace that are not sitting back behind utilities and so we're evaluating all the art of the possible.

Okay. And any idea on timing when we may hear something from you guys on that?

No, I think it's going to take I would say a couple months. We hope to get the negotiations could in the next two to four weeks but then they always go longer than we think we can get them done. So, we're keeping our stakeholders apprised of what we're doing and it's something we are to break. I am sure we would let people know.

Just stay tuned and we'll see how things progress.

Okay. I appreciate it. Have a great weekend guys.

You too Andy.

Thank you. And we do have a follow-up question from the line of Travis Miller from MorningStar. Your line is open.

I was wondering if you could kind of go through the politics at the state level in terms of potential nuclear subsidies and how this might be similar to the situation gone through several years ago with the natural gas plants that ultimately was struck down. What are some potential similarities? How has the political landscape changed and perhaps what were the lessons learned from going through the previous process?

This is related to nuclear.

No, the structuring, something similar, a subsea type of structure for nuclear relative to the natural gas plants subsidies, I'll call them subsidies, but several years ago.

Travis on the street of Oregon, since the closure of the Trojan nuclear plant, you can't build additional nuclear in the state until we've got a permanent repository associated with the fuel. There is then some work that has been done on small scale nuclear out there, but that's still got quite a bit of additional process and you might say support that's needed in the state to make any change from where we're currently are.

Okay. Thank you.

It's a way that I think in terms of what the company called New Scale Down continues to develop a small-scale 50 megawatt type unit and what is interesting, but they have a long way to go to get the commercial operation and we're not typically an R&D company and we won't necessarily be a part of that until it's actually proven and we look at the cost and structures. We do believe nuclear is if we're going to get to 100% clean future, nuclear may have to be some consideration in that mix of in the conversation.

With our current polling that we've done or actually the poling that we did in our prior IRP regarding preferences from energy efficiency to nuclear on the other scale, nuclear scored below natural gas.

Okay. Great. No, I appreciate the random question, but thanks.

Great questions and give us what's going on in the East. I don't think we're going to necessarily going to step up to any kind of nuclear exposure at this point.

No, it's really the company size to plan.

Understood. Thanks so much.

Okay. It looks like that concludes the questions. We do appreciate your interest in Portland General Electric and invite you to join us when we report our second quarter 2017 results in late July. Thanks a lot, and have a great day.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program. You may now disconnect. Everybody have a great day.