Portland General Electric Co (POR) 2017 Q2 法說會逐字稿

Good morning, everyone, and welcome to Portland General Electric Company's Second Quarter 2017 Earnings Results Conference Call. Today is Friday, July 28, 2017. This call is being recorded. (Operator Instructions) For opening remarks, I'll turn the conference call over to Portland General Electric's Manager of Investor Relations and Corporate Finance, Chris Liddle. Please go ahead, sir.

Thank you, Candace. 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'll be referencing throughout the call. The 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 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 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 second quarter earnings were released via our earnings press release and the Form 10-Q before the market opened today, both of which are available at our website 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.

Thanks, Chris. Good morning, everyone, and thank you for joining us. Welcome to Portland General Electric's Second Quarter Earnings Call. On today's call I will provide an update on our financial and operating performance, the economy in our operating area, an update on our Carty Generating Station litigation, our 2016 Integrated Resource Plan and finally the status of our 2018 General Rate Case. I'll then turn the call over to Jim Lobdell, who will provide more details on our financial performance and guidance.

Before we get started, I'd like to share with you that I'm retiring from Portland General Electric at the end of the year. It's been my great honor and pleasure to serve as President and CEO for Portland General Electric for the past 8 years. My 37 years with the company have been incredibly rewarding, and I want to express my appreciation to all of the employees here at PGE who make this a great place to work.

We have continued to raise the bar on providing value to our customers, community and to you, our shareholders. We have also continued to invest in our coworkers and our system to ensure we are providing safe, reliable and affordable energy to our customers. I am pleased to share with you that Maria Pope has been selected by the PGE Board of Directors to serve as PGE's new President and CEO. She will become President on October 1, and then will assume the additional role of CEO and join the PGE Board of Directors beginning January 1. Over the next few months, Maria and I will focus on making this a smooth transition for the company.

Now let's move into the quarter results. As presented on Slide 4, we reported net income of $32 million or $0.36 per diluted share in the second quarter of 2017 compared with net income of $37 million or $0.42 per diluted share in the second quarter of 2016. We saw an increase in energy deliveries to our residential and industrial customers related to the favorable weather conditions and strength in our high-tech sector. However, unfavorable wind production, restoration costs from the severe April windstorm, higher cost at our thermal plant and increased legal expenses related to Carty offset those gains.

We are pleased with the strength of our local economy and the growth of our customer base, and we are reaffirming our full year 2017 earnings guidance of $2.20 to $2.35 per diluted share.

Now on to Slide 5 for an operational update.

In addition to generating plant availability of 87% in our plants, our customers helped us achieved several key milestones. We continue to be ranked in the top quartile for customer satisfaction for residential, business and key customers according to Market Strategies International and TQS Research.

Once again, with the help of our customers, we ranked #1 in the nation for our voluntary green future renewable power program. According to rankings from the National Renewable Energy Laboratory released in July, we came in first in all 4 categories by some of our widest margins yet. We were first for the number of customers enrolled for the eighth year in a row, first for program sales of megawatt hours for the fifth year in a row, first for our program participation rate for the third year in a row, and first for our rate of sales for the second year in a row.

I'm also pleased to report our customers and the Energy Trust of Oregon helped make PGE one of the top 10 utilities in the nation for energy efficiency. According to rankings from the American Council for an Energy-Efficient Economy, we were ranked the 9th most energy-efficient utility among the 51 largest utilities. The ACEEE's 2017 energy -- utility energy efficiency scorecard ranked utilities' 2015 energy efficiency performance in 3 categories: quantitative savings and spending performance, program diversity in emerging areas and efficiency-related regulatory issues.

Now let's move on to Slide 6 for an update on the economy and our customers. Overall, the economic fundamentals in our service area remain very strong. Unemployment rates in June for our service area and Oregon were both at historic lows of 3.2% and 3.7%, respectively, and lower than the U.S. rate of 4.4%. The Oregon Office of Economic Analysis finds this to be an indication that Oregon is at or near full employment. As a result, Oregon's employment rates will slow while maintaining a slight growth advantage relative to the entire U.S.

Additionally, Oregon posted one of the nation's biggest gains in gross domestic product for the second straight year. According to annual GDP data released in May, Oregon's growth rate of 3.3% in 2016, largely attributable to durable goods manufacturing related to the high-tech sector, ranked second in the nation after Washington at 3.7% according to the U.S. Bureau of Economic Analysis.

The continued strength of Oregon's economy contributed to an increase in our total customer count of approximately 1.3% compared to the second quarter of 2016.

We continue to expect weather-adjusted energy deliveries in 2017 to decrease between 0% and 1%. This is based on an expected decrease in deliveries to metal manufacturing customers, ongoing energy efficiency efforts, which are lowering the residential and commercial load growth rates, and 2016's leap year, which is equivalent to a 0.3% decline in growth this year on a full year basis.

During the next few years, we expect to transition back to long-term positive annual energy delivery growth of approximately 1%, which reflects a reduction in deliveries due to energy efficiency. In particular, we're forecasting growth in the high-tech sector and the continuation of strong in-migration.

Moving to Slide 7. We have provided an update on the Carty Generating Station, our 440-megawatt gas baseload [storage] near Boardman, Oregon, that went into service in July of 2016. As of June 30, we had $635 million, including AFDC capitalized cost for the project.

As previously noted, we are pursuing legal actions against Liberty Mutual and Zurich North America, the 2 sureties who provided the performance bond in connection with the Carty construction agreement.

On July 10, the Ninth Circuit Court of Appeals overturned a federal judge decision that banned arbitration of our claims against the sureties. On July 24, we filed a petition with the Ninth Circuit Court requesting a rehearing en banc. This means the decision may be reviewed by all of the sitting Ninth Circuit judges, which if granted, could delay the ICC arbitration.

If the initial decision by the Ninth Circuit is not overturned, the International Chamber of Commerce tribunal will decide whether the lawsuit is arbitrable in the International Court of Arbitration. Our jurisdictional evidentiary hearing before the ICC is scheduled -- currently scheduled for October 31. For more details, you can refer to our 10-Q.

Slide 8 provides an overview of the timeline and action plan for our 2016 Integrated Resource Plan that we filed with the OPUC in November of 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 4-year planning period. Additionally, it calls for taking actions to apply approximately 175 average megawatts of qualified renewable resources and 560 megawatts of dispatchable capacity. We expect the OPUC to issue a decision on our IRP on or before August 31.

Currently, we are engaged in productive bilateral negotiations with the owners of existing regional resources to fill our remaining capacity needs, and we are completing detailed term sheets with potential sellers. By mid-August, we plan to request a waiver from the OPUC of the guidelines that call for a competitive bidding process for resources greater than 100 megawatts and a term of more than 5 years.

Following the acknowledgment of the IRP and the outcomes of the bilateral negotiations and waiver process, we may request approval from the OPUC to issue a request for a proposal for any remaining capacity needs.

We have also proposed conducting an RFP for renewable resources as soon as possible if the commission issues an acknowledgment order that includes the need for renewable resources. The RFP process will include review and input by our stakeholders, oversight by an independent evaluator who reports to the OPUC staff, and overall by -- overall review by the OPUC itself.

Since issuing the IRP, we have identified a potential benchmark wind resource that could have a nameplate capacity of up to approximately 500 megawatts that would qualify for production tax credits. We are continuing to explore this option. The submission of this resource into an RFP for renewable resource as a benchmark that is subject to our additional due diligence, negotiations and the execution of definitive agreements.

Our IRP is a flexible, balanced plan that reflects our commitment to a low carbon future and provides the best balance of cost and risk for our customers. It puts us ahead of schedule for Oregon's renewable power goals, and enables us to serve approximately 50% of our customers' energy needs from carbon-free resources by 2020.

Now let's move to Slide 9 for an update on our 2018 General Rate Case filed at the end of February of this year. For your reference, key drivers are included on the slide, and additional details can be found in our 10-Q. The case is progressing as scheduled with several rounds of settlement discussions completed in the last few months. We have already come to agreement on some key items, including depreciation expense, net variable power costs and a partial settlement on other items.

The case will now focus on items such as our load forecast, budget for additional employees, our cost of capital and the year-end estimate of completed capital additions. We filed our reply testimony on the remaining items on July 18, and the settlement conference is scheduled for August 3 and 4. We expect the final order from the commission by the end of the year for a price change effective January 1, 2018.

Now I'd like to turn the call over to Jim Lobdell, who will go into more depth on our financial performance and guidance. Following these remarks, we'll open the lines for your questions. Jim?

Thank you, Jim. Turning to Slide 10 as Jim mentioned, for the second quarter of 2017, we recorded net income of $32 million or $0.36 per diluted share compared with net income of $37 million or $0.42 per diluted share for 2016. This slide represents a walk-through of the income statement changes year-over-year.

A few things to note on this slide are: first, revenues increased $13 million for the quarter. This was largely the result of increased retail deliveries due to favorable weather but was partially offset by a reduction in prices from our 2017 annual update tariff.

Second, a $5 million decrease in power costs as a result of a decline in the average price of purchased power, driven in part by favorable hydro conditions, which was partially offset by an increase in total system loads and a 20% reduction in wind generation.

Third, generation, transmission and distribution costs increased by $10 million due to restoration efforts related to the severe April windstorm as well as maintenance costs at our Carty, Beaver, Port Westward and Boardman generating stations.

Fourth, administrative and general expense increased by $3 million due to approximately $1 million of Carty litigation expense and $2 million in other A&G expenses.

And finally, an increase in other miscellaneous expenses, such as depreciation and amortization expense, due to Carty being placed in service in July 2016 as well as a decrease in AFDC equity due to a lower CWIP balance.

Onto Slide 11, which shows earnings drivers for the quarter. First, gross margin increased earnings by $0.11 due to the following: an $0.08 increase due to more favorable weather and a $0.03 increase in the estimated collection under the decoupling mechanism.

The next driver is a $0.05 decrease due to plant maintenance costs comprised of $0.02 due to the maintenance of miscellaneous Carty plant equipment, including communication and control equipment, monitoring, water treatment and safety systems. In addition, approximately $0.02 is due to the timing of the planned maintenance work at the Beaver, Port Westward and Boardman plants when compared to the same period of 2016, and a $0.01 due to maintenance of 3 generating units at the Beaver plant.

Third, a $0.04 decrease due to storm restoration costs caused by a severe April windstorm that brought gusts of up to 70 miles an hour. Response efforts involved more than 1,000 employees, as the storm affected more than 255,000 of our customers, and knocked down approximately 1,300 wires across our service territory.

The fourth driver is a $0.04 decrease in production tax credits resulting from a lower wind generation at the Tucannon River and Biglow Canyon windfarms.

The next driver is a $0.02 decrease related to Carty, $0.01 for the depreciation and incremental carrying cost of Carty's capital spending greater than the $514 million in customer prices and $0.01 for our litigation costs. Finally, $0.02 due to higher A&G costs.

On to Slide 12, we have provided a summary of the company's current capital expenditure forecast from 2017 through 2021. These expenditures related to investments we are making in our system to keep it safe and reliable and new technologies to meet our customers' changing energy needs and service expectations. We have not included any capital expenditures related to potential projects pursuant to our 2016 Integrated Resource Plan.

Slide 13, we continue to maintain a solid balance sheet, including strong liquidity and investment-grade credit ratings. As of June 30, 2017, we had $697 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 50.4%. The company has a $500 million revolving credit facility to meet the company's liquidity needs, which has a maturity date of November 2020, and additional letter of credit facilities totaling $220 million.

We'll be issuing $225 million of first mortgage bonds at an interest rate of 3.98%. $75 million will be funded in August maturing in 2048. The remaining $150 million will be funded in November maturing in 2047. And we will be -- and we will use the proceeds to repay our bank loan due in November 2017. We expect to issue up to an additional and an incremental $75 million of first mortgage bonds later this year.

As shown on Slide 14, we are reaffirming full year 2017 earnings guidance of $2.20 to $2.35 per diluted share. The guidance is based on the following assumptions: a decline in retail deliveries between 0% and 1%, weather adjusted; normal hydro conditions for the remainder of the year based on current hydro forecasts; wind generation for the remainder of the year based on 5-year 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; and revised operating and maintenance costs between $555 million and $575 million, driven by increased distribution costs. Back to you, Jim.

Thanks, Jim. In summary, on Slide 15, we continue to focus on successful execution of initiatives that drive value for our customers and our shareholders. First, maintain our high level of operational excellence, with a continued focus on employee and public safety and meeting our operational and financial goals. Secondly, working collaboratively with all of our stakeholders to obtain acknowledgment of our 2016 Integrated Resource Plan and its associated action plans to meet our customers' future energy needs; and third, achieve a fair and reasonable result in our 2018 General Rate Case.

And now, operator, we are ready for questions.

(Operator Instructions) And our first question comes from Paul Ridzon of KeyBanc.

The bilateral discussions, are you talking about contacts, or are you talking about actually buying capacity from these owners?

Yes to both. We're looking at all options. We're investigating all options and we are talking to both people who would provide us capacity under contract and potentially, assets that we could potentially purchase. So we're working through that right now and in detailed negotiations with a number of parties.

How much liquidity are you seeing in that market for assets?

I'd say we're well aware of all of the generation that exists in the marketplace because we are a very nimble player out there. And as such, we recognize that there is some available capacity. It is somewhat limited but there's enough that we think that we could accomplish most of what we need to do.

Okay. And what was the capacity factor on wind in the quarter? And was that down 20% versus the benchmark or is that versus last year?

That's quarter-over-quarter, Paul. And I think the capacity factor was in the 30% range for wind for the quarter. I'll need to confirm that because that's off the top of my head.

And do you know what the wind was versus what's in the benchmark?

In the [A18] filing?

I'd have to go back. Paul, I'll get back to you on that.

I think it was like 20% down, a little over 20% down against the [A18].

Okay. And then lastly, a little bit of noise on the line. I want to make sure I understand that what the Ninth Circuit did. They threw out a band, and if that action stands, you'll have to go to international arbitration, is that correct?

Right. As the Ninth Circuit Court stands, then we would go to ICC arbitrations to determine the arbiter [volments] of the claim, and then we would go through the actual merits of the case. So that was -- so the ICC have to determine the jurisdiction issues first, and then we have to -- if they decide they have jurisdictions, then we would work with -- through them on the merits of the case.

Would you call that an incremental negative?

No. I just think it's the nature of the court system that they tend to look at arbitration as a more favorable way of the solving issues. We still think we have a good argument, that this should be resolved in the Ninth Circuit. The merits of our case are still very strong.

Do you think this will affect the timeline if the Ninth Circuit stands?

Hard to tell at this point. Both are a fairly lengthy process.

We still think it's going to take 2 to 4 years to resolve all the claims that are out there.

And our next question comes from Brian Russo of Ladenburg Thalmann.

Could you just tell us what the PCAM or how many -- how far below the bench were -- the benchmark you are with the deadband in 2Q?

We are about $5 million below.

Okay. And the renewable benchmark you've referenced before, can you elaborate it at all? Is that a self build or is that an existing asset or build on transfer?

The subject is a confidential negotiation, so we really can't talk much about it. But we still want to do what we did with Tucannon River Wind Farm in terms of the opportunity.

Got it. Okay, and do you have a storm costs recovery mechanism or do you have to absorb those costs from April? And why aren't they deferred?

Yes, Brian, we do have a mechanism. We get $2 million a year that goes into a balancing account to cover level 3 storms. We have exhausted that balance in last year, and we've exhausted $2 million this year. So the fund is now empty, and there is nothing else to offset future storm. We have filed for a deferral for the excess storm cost this year. That will be subject to a review by the commission probably next year. In the current rate case, we are working on settlements, I don't know if that's public yet, but the settlement on potentially increasing the amounts of the storm reserve costs. And once that becomes public we can share that. But we've been having dialogues with the commission staff on this issue and the parties. So right now, it's -- the fund is empty and we have filed the deferral for the excess costs this year, but have not reflected that in our earnings.

Got it. And so it looks like the 2 big headwinds in the second quarter was the lower wind output and these storm costs, yet you reaffirmed your guidance. So are there some positive offsets that kind of allow you to reaffirm your guidance, or are you biased towards the lower end? Just some granularity on that.

So, Brian, a couple good things happened. We've obviously had good load growth due to favorable weather this year. So loads have been higher than we expected in terms of -- due to weather, that's one good thing. And we've had very good hydro conditions that have kept prices low in the region. And so those low prices have allowed us to take advantage of lower prices and offset our thermal operations. So those are the 2 positives that have kind of worked in our favor.

And our next question comes from Travis Miller of Morningstar.

A quick question, I want to make sure I caught you correctly. Is there 500 megawatts of new wind that you've identified outside of the IRP?

No. It's 500-megawatt nameplate. So that would be around 170 megawatts average, more or less. So that's what we've identified as a benchmark resource that would hopefully compete well in an RFP, if we go to an RFP.

Okay. And that's still within -- is that still within the IRP?

Yes. So we would have to get acknowledgment from the Oregon Public Utility Commission on an action plan that included acquiring new renewable resources. And that's what we're waiting for from the commission. Hopefully, we'll get that decision on or before August 31 of this year.

Yes, okay. And it could be -- would you -- then you say, bid competitively as a self-build as well as an RFP?

If they agree that we should add more renewable, take advantage of the production -- the value of the production tax credit, we would work on an RFP with the stakeholders. We'd issue that RFP, we would hope to include a benchmark resource in that RFP. But, again, that's subject to completing negotiations with the third party on that benchmark resource.

Sure, okay. And is any of that in your CapEx plan in terms of the self build?

No.

And our next question comes from Gregg Orrill of Barclays.

Regarding the General Rate Case. Can you talk about what you're seeing in the settlement discussions and where you see that headed?

Jim, you want to cover this?

We've got additional settlement discussions, Gregg, going on, on August 3 and 4, and we'll be talking about the issues that we haven't currently settled. As Jim mentioned, we settled net variable power costs, depreciation and a few other items. So we still have quite a ways to go, and we'll see how those discussions turn out next week.

And our next question comes from Andy Levi of Avon Capital.

Sorry to see you leave, Jim.

It's been a great career.

It was a good career. I should be so lucky.

After 44 years [only], you can do that.

Yes, I am working on it, working on it. But yes, you did a great job. So -- but again, sorry to see you go but I remember Maria, so I think she'll do a great job.

This will be great.

Just us to be clear, just on this whole kind of regional resource thing, for no better way to put it. So basically, just off the wind, your else -- I mean, I guess, you're negotiating on either buying or buying capacity or buying a power plant, a gas-fired power plant or buying power from a gas-fired power plant. Is that kind of what you're trying to say?

Or from other regional players who have excess capacity. So it would be both from existing thermal resources as well potentially from existing hydro resources, so we're examining both. And in terms of the contracts, those would tend to be shorter duration and obviously, if you bought a thermal resource, that would be longer duration.

Okay. And the part about the waiver, does that go for the entire -- any type of scenario or only if you were to purchase a plant?

It would only come into place if the agreement that we entered into had greater than 100 megawatts in capacity and longer than a 5-year term. So under those 2 conditions, we're required to get a waiver under the competitive bidding guideline.

Okay. So it has nothing to do with either purchasing power or purchasing a plant itself?

It's really related to the nameplate of the capacity.

Right. I understand. Okay. And can you categorize in any way where you're leaning towards or where the negotiations on the various different opportunities you have? Are you leaning more towards buying a plant or just buying power, doing a PPA?

No. We are using the same criteria we would do in an RFP -- an RFP process. We're looking at lowest-cost least risk, and that's our standard. We want to ensure that we can deliver value to our customers, and we want to ensure that the actions we take provide the best balance of cost and risk.

Okay. And then separately, just to understand, you're also in negotiations, as you said, on a renewable resource, which is separate, right?

Yes. Separate.

And we should hear something -- if I am reading this correctly, we should hear something from you guys sometime in August on both, is that what you're saying?

Well, we would hope to get a commission decision on our IRP on or before August 31. (inaudible) action, and that action plan, if they approve, will give an indication whether we're going to move forward on an RFP for renewable energy.

How about on the gas-fired capacity?

The capacity will be more related to whether they approved or we get a waiver on the ability to find short duration capacity contracts or potentially, thermal resources that might be already in existence. So watch the waiver process. The waiver process we hope to file in mid-August, that would give you an indication of what actions we're taking on the capacity side. And on the renewables side, I would look towards the end of August to see what the commission action is on our IRP.

So will you only file the waiver once you have a resource in mind?

We want to get to decision...

Or is it based on the IRP outcome?

No, it's really -- we know what the need is. I think we feel fairly comfortable that we need 500-megawatt of flexible capacity. So that's the first piece and so we think the need is there. The waiver really is necessary to obviate the needs for an RFP in terms of duration and quantity on the actual agreements.

(Operator Instructions) And our next question comes from [Ashar Khan] of [Wardian].

Jim, congratulations, a long career. But I wanted to ask a question strategically. If I am right on Bloomberg, I have your date right, it said you started on January 1, 2009. And over these, I guess 9 years coming up, I guess by the time you retire, the sector has changed and especially small-cap companies like yours have been sold. The only area that is left in the U.S. is the Northwestern. We just saw a neighbor of yours just go out about 2 or 3 weeks back. So as the board went through the succession planning process, and the utility multiples are at the highest. You couldn't get better multiples now than ever in the history. Has the board strategically looked at putting the company up for sale? And if not, why not in this environment? And just with your size left in terms of the competition as we go through this succession.

Well, [Ashar], we don't really comment on mergers and acquisition conversations. That's just our standard policy. I will assure you that the board is always having conversations around all regional issues and we're aware of what's going on in the region and that's really where I'll end the conversation. I think we believe in our strategy, we believe in the direction we're going. We have opportunity to grow value for our customers and our shareholders and we'll continue to pursue that path.

So this -- you can't share whether this has been -- have you considered this or not considered it at all?

Can't comment on that.

And that concludes our question-and-answer session for today. I'd like to turn the conference back over to Jim Piro for closing remarks.

Thank you. We appreciate your interest in Portland General Electric, and invite you to join us when we report our third quarter 2017 results in late October. Thanks a lot, 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. Everyone have a great day.