Bill Valach - Director, IR Jim Piro - President and CEO Jim Lobdell - SVP-Finance, CFO and Treasurer.

Paul Ridzon - KeyBanc Capital Markets Sarah Akers - Wells Fargo Brian Russo - Ladenburg Thalmann Mark Barnett - Morningstar Andrew Weisel - Macquarie Capital.

Good morning everyone, and welcome to Portland General Electric Company's Third Quarter 2014 Earnings Results Conference Call. Today is Tuesday, October 28, 2014. (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, Shannon, and good morning everyone. We are pleased that you're 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 discussions, and we’ll be referencing that presentation throughout the call.

The slides are also available on our website at portlandgeneral.com. Referring to slide two, I'd also like to make our customary statements regarding Portland General Electric’s written and oral disclosures and commentary.

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 the 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 third quarter earnings were released via our earnings press release, and the Form 10-Q before the market opened today, and the release is available at our website at 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. And these Safe Harbor statements should be incorporated as part of any transcript on this call.

As shown on slide three, 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 an update on our operating performance, our outlook for 2014, service area economy and strategic initiatives.

Then Jim Lobdell will provide more detail around the third quarter's results, and discuss our 2015 general rate case. And following those prepared remarks, we will open our lines 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 third quarter earnings call. As presented on slide four, we recorded net income of $39 million or $0.47 per diluted share in the third quarter of 2014, compared with net income of $31 million or $0.40 per diluted share in the third quarter of 2013.

PGE continues to demonstrate strong operational performance across the company in 2014. Construction of our three new generating resources is proceeding on time and on budget.

We have now settled all items for our 2015 general rate case with the OPUC staff and interveners and we are now in the range of our full year 2014 earnings guidance by $0.05 from $2.05 to $2.20 per diluted share to $2.10 to $2.20 per diluted share. Now for an operational update on slide five.

Our generating plants operated very well in the quarter, with PGE generation availability at 92%. Customer satisfaction remains strong with our national rankings in the top quartile for residential customers, and top decile for general business and key customers.

As mentioned in our last call, this quarter we undertook a project to exchange 70,000 residential meters in our service area that do not meet PGE's operational and safety standards. Work is over 95% complete and on track to be finished by the end of this week.

We plan to capitalize the majority of replacement costs which are estimated to be approximately $7 million to $8 million. Turning to slide six. Now for an update on the economy in our customers. PGE experienced a 4.7% increase in energy deliveries this quarter compared to Q3 2013.

This increase is on a weather adjusted basis, and excludes one large paper customer. We continue to see positive economic trends in our service area and these trends are translating into growth across all sectors but particularly in the commercial and industrial sectors.

Our overall customer count is up 1%, and new connects are up 15% year-over-year due primarily to strong multi-family construction activity in the region. In addition to ongoing expansion in the high tech sector, the overall service area continues to show signs of economic growth and new development.

In the past quarter, a transportation manufacturing company announced increased demand for a barge and rail cars. Construction began on a new data center which is expected to be operational by mid-2015 and there is continued expansion at the Port of Portland. Employment indictors in our service area continue to be encouraging.

Job growth in Oregon has been strong this year, growing at 2.2% in September with an emphasis in the professional and business services, government and leisure and hospitality sectors.

Also this quarter we’ve seen more people joining Oregon's labor force indicating increased optimism in the labor market as more people join or migrate to Oregon looking for employment opportunities. In addition, the unemployment rate in our service area dropped from 6.4% a year ago to 6% in September.

As a result of these positive economic signs and a low growth in the third quarter, we are maintaining our loan growth forecast based on normal weather of approximately 1% over 2013 weather adjusted results. This again excludes one large paper customer.

This forecast is net of approximately 1.5% of energy efficiency based on the energy trust of Oregon's projected programmatic energy efficiency savings for 2014. Now let me update you on the construction of our three new generating resources which all continue to be on time and on budget.

Slide seven provides detail on Port Westward Unit 2, a 220 megawatt natural gas flexible capacity resource under construction in Clatskanie, Oregon. Mechanical completion has been achieved and we have commenced startup activities including test fires of all 12 engines.

This resource will assist us in better managing load requirements and integrating renewables into the grid. The projected estimated capital cost is approximately $300 million excluding AFDC and it is expected to be operational in Q1 of 2015.

Turning to slide eight, we have provided details on Tucannon River, a 267 megawatt wind farm located in Southeastern Washington. All 116 turbines have now been erected, over 100 are mechanically complete and testing is underway.

The projects estimated capital cost is approximately $500 million excluding AFDC and it is expected to be operational by the end of 2014 or early Q1 of 2015. Lastly, slide nine summarizes the Carty Generation Station, of 440 megawatt natural gas base-load resource under construction in Boardman Oregon.

Engineering design and procurement are nearing completion and foundation work continues for the gas and steam turbine. In addition, major components such as the heat recovery steam generator and the cooling tower are being delivered and installed.

The plan is expected to be operational in mid-2016 with a total capital cost estimated approximately $450 million excluding AFDC. Slide 10 provides a summary of the company's five year capital expenditure forecast. The new generating projects are expected to result in an average rate base increase of $1.2 billion in 2017.

We expect the three new generation projects along with the base business capital expenditures to result in an average rate base of approximately $4.5 billion in 2017. Now for a regulatory update. In February, we filed a general rate case with a 2015 test year, focused primarily on cost recovery for Port Westward Unit 2 and Tucannon River Wind Farm.

We have now settled all items with the OPUC staff and interveners and expect this commission to issue a final order before the end of 2014, which will result in an average overall price increase of approximately 1%. In February of 2015, we expect to file a general rate case for a 2016 test year. That will include cost recovery for Carty.

In other regulatory activity on October 23rd, the OPUC staff issued a memorandum and proposed order on PGE's 2013 in a greater resource plan recommending to the commission the acknowledgment of our plan with one additional study. There are no significant capital expenditures associated with this IRP.

The 2013 IRP will be considered by the commission at a public meeting on November 12th.

We now expect to start preparations for the 2016 integrated resource planning cycle that will evaluate options and make recommendations for both the replacement of Boardman as well as additional renewables to meet Oregon’s renewable portfolio standard up 20% by 2020.

Now I’d like to turn the call over to Jim Lobdell, who will discuss our financial results for the third quarter and provide additional details on the 2015 general rate case.

Jim?.

Thank you, Jim. Turning to slide 11, as Jim mentioned, the third quarter of 2014 we recorded net income of $39 million or $0.47 per diluted share, compared with net income of $31 million or $0.40 per diluted share in the third quarter of 2013.

The increase in earnings was driven by an increase in price and energy deliveries, lower net variable power costs, and an increase in the allowance for equity funds used during construction for the company's three new generating resources.

Increased energy deliveries were driven by normal weather combined with increased demand from new construction and high tech industry expansion. Moving to slide 12, total retail revenues for the third quarter of 2014 increased $31 million to $434 million.

This increase was primarily driven by a $17 million increase from higher sales volume, $16 million from the January 1st price increase and a $5 million increase from the collection of deferred cost associated with four capital projects.

These increases were partially offset by $6 million estimated refund to customers related to the decoupling mechanism. Total actual energy deliveries for the third quarter of 2014 were 4.1% higher than the third quarter of 2013.

Our customer segments saw increased energy deliveries, as residential up 5.2%, commercial up 3.5% and industrial energy deliveries up 3.6%.

Purchase power and fuel increased by $12 million consisting of $21 million from an 11% increase in total system load, partially offset by $9 million from a 4% decrease in the average variable power cost per megawatt hour.

Net variable power cost, which consists of purchased power and fuel expense, net of wholesale revenues, decreased $5 million for the third quarter of 2014 compared to the third quarter of 2013. The decrease in net variable power cost was driven largely by improved thermal plant performance.

During the third quarter of 2013, the company experienced unplanned outages at three of its thermal plants which drove an increase in the average cost per megawatt hour resulting in higher energy replacement costs during that period.

Net variable power costs were $5 million above the baseline this quarter compared with $9 million above the base line in the third quarter of last year. Net variable power cost year-to-date Q3 2014 were $9 million below the baseline. This compares to year-to-date Q3 2013 net variable power costs which were $5 million below the baseline.

Year-to-date costs are within the deadband and we have not recorded a collection or a refund. Moving on to slide 13, production, distribution and administrative costs totaled $114 million for the third quarter of 2014, an increase of $11 million from the third quarter of 2013.

The increase in operations and maintenance expense primarily consisted of $5 million increase in plant sub-station and line maintenance expenses, $5 million in increased incentive expense resulting largely from higher net income, and a $1 million increase due to the increase in PGE's ownership interest in the Boardman coal plant from 65% to 80%.

Depreciation and amortization expense increased $14 million quarter-over-quarter, driven primarily by two factors. $9 million related to the timing as a deferral and amortization of cost for capital projects and $3 million related to the overall increase in capitalizations.

Total interest expense decreased $2 million quarter-over-quarter, as the $3 million increase in long term interest expense was more than offset by a $5 million decrease and AFDC debt.

Other income increased $5 million quarter-over-quarter driven by a $7 million increase in AFDC from equity funds which was partially offset by lower earnings related to the non-qualified benefit plan trust assets. Income tax was $16 million in the third quarter of 2014 compared with $4 million in the third quarter of 2013.

The increase is largely due to the combination of higher pre-tax income for 2014 compared to 2013, and the timing the recognition of production tax credit.

Moving on to slide 14, as Jim previously mentioned, we’ve reached an overall stipulated settlement with the OPUC staff and interveners in September, that resolved all remaining matters in the case.

The key items in the stipulated agreement are, our return on equity of 9.68%, capital structure of 50% debt and 50% equity, cost of capital of 7.56%, and a rate base of $3.8 billion, which is based on a stipulated in-service amount of $323 million for Port Westward 2, and $525 million for the Tucannon River Wind Farm.

The estimated net increase in annual revenues from this stipulation is $17 million, which approximates a 1% overall increase in customer prices. PGE expects the OPUC to issue a final order before the end of 2014 with new customer prices expected to become effective in 2015.

On the slide 15, we continue to maintain a solid balance sheet, including adequate liquidity in investment grade credit ratings. As of September 30th, 2014, we had $793 million in cash and available short term credit, $692 million of first mortgage bond issuance capacity, and a common equity ratio of 44.9%.

We have largely executed our current financing plan under which we obtain $305 million, 18 month unsecured loans, and issued $200 million of first mortgage bonds under our $280 million bond purchase agreement. We expect to issue the remaining $80 million of first mortgage bonds in November of this year.

This flexible financing plan has allowed us to finance our new generation resources in a cost effective way. And regards to the issuance of new equity, we continue to expect to draw upon our outstanding equity forward during the first half of 2015.

Moving on to slide 16, as Jim previously mentioned, Fiji is narrowing it’s guidance range for its earnings from [$2.05] (ph) to $2.20 per share to $2.10 to $2.20 per share.

This change reflects our lower operating expenses and as a result we’re lowering our guidance for operating and maintenance expense from a range of $480 million to $500 million to $475 million to $495 million. All the guidance assumptions remain largely unchanged. Back to you Jim..

In summary, we continue to focus on successful execution of our business strategy, including completing our three new generating resources on time and on budget, achieving fair and reasonable results on our 2015 general rate case, and ensuring high quality, reliable, and safe operations across our system, that delivers value to our customers and our shareholders.

And now operator, we're ready for questions..

Thank you. (Operator Instructions) Our first question is from Paul Ridzon of KeyBanc Capital Markets. You may begin..

Can you refresh us on what you expect the tax rate to be for the year?.

Effective tax rate for the year we expect to be about 25% to 30%..

And how do you expect to draw the equity down -- in one lump sum, or kind of trickle out as you start to spend more capital?.

Paul, probably it would be more towards the lump sum, towards the back end. .

Towards the back end of the first half?.

Yes..

Okay.

And then I don't know if you quantified weather, but what did weather do in the quarter on a per-share basis, if you have that?.

It’s about $0.03..

Positive, I take it?.

Yes..

And then, lastly, you mentioned a $6 million refund.

Was that related to prior periods, or prior years?.

$6 million refund during the quarter?.

You talking about the PCAM? Is that what you are asking about, or -.

I think it was decoupling..

Okay. Yeah, that would be the year-to-date number..

Okay.

So, that’s always in this current year?.

Yeah..

Okay. Thank you very much..

Thanks Paul..

Thanks, Paul..

Thank you. Our next question comes from Sarah Akers with Wells Fargo. You may begin..

Good morning, Sarah..

Good morning. In the past, you have talked about a new customer billing system for about $100 million.

Can you update the status of that project? And are there any other incremental investments that might bolster the CapEx in the 2017-2018 timeframe?.

We continue to pursue replacement of our customer information system as well as what’s called the meter data consolidate, which is the interface between our smart meter system and the customer information system.

So, we have approval for that project, we’ve got good support from the regulatory agency in terms of moving that project forward and it’s now included in our CapEx forecast..

Okay, so the 14 to 18 CapEx I think went up about $125 million, so that's what's going on there?.

Most of that is the billing system, plus other adjustments to our capital forecast..

Got it.

And then, in the absence of any new projects in the 2017-2018 timeframe, what are your thoughts on share buybacks there?.

It’s too early to tell at this point. We’re going to continue to evaluate our capital needs and our capital expenditure program and as we get closer to that we’ll look at that – along with other options in terms of keeping our capital structure in kind of that 50-50 range. A lot of it will depend on how the IRP works through this next IRP workthrough.

We want to leave ourselves flexibility so if we do decide to construct additional resources, we’ll have the right capital structure to do that..

Got it. And then the last one, the guidance raise appears to be supported by the lower O&M. But then you also have the $9 million PCAM benefit year-to-date, and then it looks like a little bit of weather benefit.

Are there any offsets to those PCAM and weather benefits that are preventing something more than the $0.05 guidance raise?.

Sarah, we still got another quarter to go and it’s always a volatile quarter with the weather and the winter timeframe. So, right now I’d say no, they are not..

Perfect. Thanks a lot..

Thank you. Our next question is from Brian Russo of Ladenburg Thalmann. You may begin..

Hi, good morning..

Hi, Brian..

Hello Brian..

Could you just remind us how much capacity is being retired at Boardman, and then how much additional capacity you need to meet the 2020 RPS?.

Boardman is about 585 megawatts. We own 90% - we’ll own 90% when we execute the last 10% share. We have our purchase option in front of the commission which we expect them to approve which will execute by year end. That will put us at 90%with the other 10% owned by Idaho Power.

So, you take 585x the 90 and you get our share of Boardman, in times of that 80% - 85% capacity factor. So, that’s the piece that we’re going to have to address in the next IRP. And there's a lot of interest in both gas as well as additional renewable to replace that. We're going to have to run a number of portfolios.

We’re also looking at the 111 (d) rules and how that plays out. So, that’s a whole analysis that we’re going to be doing for the next IRP. In terms of the renewables, every 5% is worth about roughly 100 megawatts - 100 average megawatts. We should be about 300 megawatts of name plate if you assume about one-third capacity factor.

We're primarily looking at wind, but we’re also as you know we’re doing some research at Boardman on biomass, but that’s very, pretty much R&D at this point. But we’re looking for diversity on our renewables. But that’s kind of the magnitude of what we’re going to be looking for in the next integrated resource plan.

We’ll continue to support energy efficiency. We’re going to have to do some work on the demand side. We continue to look at demand side programs to control our load and to make it better load to meet. So, those are the kinds of things we’ll be looking at the next IRP. We’re also – to extent we add more wind resources.

We’re going to have to look at additional gas, flexible resources like Port Westward Unit 2, as we will need capacity to back that up. .

Got it. That's very helpful. Thank you. And I know there are restrictions on increasing the dividend while the forward sale is still awaiting settlements.

But when we look, say, in the second half of 2015, and we look at where your payout ratio is today, in the low-50% range, is it reasonable to assume a meaningful step-up in the dividend when we get to the second half of 2015?.

So, we typically look at the dividend in our May Board meeting and the Board understands kind of what the low end of the guidance. We’re going to evaluate that as a time, we’ll look at all the factors and we will launch a state within our guidance between 50% and 70%.

So, I can’t handicap how the Board is going to look at it, but we’ve had really good conversations around the dividend and we’ll make a decision in May and move forward. But, the Board is committed to understand the value of the dividend to our shareholders..

Okay. Thank you very much..

Thank you. Our next question is from Mark Barnett of Morningstar. You may begin..

Hey, good morning everyone..

Good morning, Mark..

Just a couple of questions, one on the rate case filing. I've seen some of the documents. But can you talk about -- there were some revisions, and I know some of them are non-cash.

But are there going to be any challenges in those numbers to hitting the allowed ROE in the filing? Is that something that you would be comfortable talking about?.

What I will say is that - a good part of it – I mean we recently went out with $81 million with a request and some of it is cash and some of it is non-cash. And as you know we ended up with $17 million at the end as far as the net after accounting for the credits. And embedded in that is a change in base business of about $41 million.

Now, as I was saying, a good part of that is appreciation which isn’t going to impact us. And then there were a lot of updates associated with power cost and loads and project timing and things of that nature.

So, really gets down to a small number of that, we’re going to have to adjust our own infrastructure in order to deliver alignment with that GRC case, at this particular point. So, I think that we can meet the challenges going into 2015..

Now there’s a couple of items in the rate case that we typically don’t get recovery for, the incentives for officers and that portion of the other employees incentive plans, that tends to have a difference between our allowed and our actual ROE.

Our corporate contributions to non-profits and others and lobbying expenses, those - and image advertisings.

So those ones are the typical ones, they’re not big, I think we‘ve typically talked about 100 basis points spread between our allowed and our actual because of those disallowances which are still - real expenses for the company, that number is going down as our rate base grows and Jim I don’t know if you can provide any guidance on that..

Yeah, there is about 65 basis points where the difference is, what it usually accumulates to. And that's by the time we get to 2017..

Did that make sense?.

Yes, no, thanks a lot. I really appreciate that detail. And if I could, just one more sort of bigger-picture question. Your long-term load growth numbers, when you are looking at your generation needs for these next processes, it's a fairly large impact from energy efficiency you have baked in for 2014.

Is this the kind of thing where you are still hitting the low-hanging fruit, or do you expect to keep that sort of a run rate over your load planning horizon?.

We've been working with the energy trust on this specific item trying to understand the supply curve as we go out in time, especially with low gas price environment. We’ve been doing about 35 average megawatts a year which is that 1.5% we’ve been talking about.

When you look at the supply curves over time, that number starts going down in the later years. It’s not next year but probably year after that, it starts diminishing as we’ve been doing those for a long period of time.

So absent any new technology those numbers are dropping off probably down in the 20 average megawatt range more in the 1% range and maybe even lower unless new technology comes about. So, the energy trust and PGE's continue to work on what that supply curve look like, what measures might be cost efficient.

But in this low gas price environment many measures don’t become economic. And so those are things that we’ll be evaluating in our integrated resource planning process in the next cycle. But, so it does kind of tail off. And if you go out many, many years it gets very low, absent any new technology changes..

Great. Thanks for all of the detail, guys..

Thank you. (Operator Instructions) Our next question is from Andrew Weisel of Macquarie Capital. You may begin..

Good morning, Andrew..

Hi, Andrew..

First, a small one.

The increase in the base capital spending that Sarah had asked about -- was that included in the settled 2014 rate case, or will that be rolled into next year's rate case?.

The customer information system will not be completed until early 2017, I think maybe after the first quarter sometime, first or second quarter. So, it's not in any rate case at this point, and would not be part of the 2016 rate case the way we contemplate it today as of 2016 test year.

So, we would evaluate that in the 2017 time frame and the real question there is, given all the other changes going on with depreciation and all the other things, we will look at 2017 to determine whether we need to file a rate case for 2017 to cover the cost of that or it can be covered under the normal operations.

So, but it wouldn’t really show in service till 2017..

Got it, that's helpful. Okay, then on next year's rate case, you mentioned Carty is obviously the big one.

From a high level, can you talk about what some of the other puts and takes might be? Would there be any opportunities for credits that might offset the impact, like you found in the cash one? And just from a very high level, what the impact on customer rates might look like..

So, Jim will give you the increase for Port West, I mean for Carty. We’re still looking at 2016 to see how the year shakes out. We’re just going to the O&M budgets at this point and the load forecast, all those have to be factored into our kind of thinking. The number for Carty has come down.

I think we were talking 6% to 8% before and now we’re down to 4% to 6%. So, it’s come down as we’ve got better estimates of the capital and depreciation in all the components of that project.

So, we will look at that and then we’ll make a decision here in the next month or so on the actual structure of the rate case, but right now, just as the throes of going to the O&M budgets and getting the load forecast for 2016 so that we can make an informed decision on how the overall year shakes out..

In regards to the credit for the DOE decommissioning refund, that’ll be about $17 million that will carry over into that time frame as well. And then also in 2016 there will be some of the BPA regional Power Act fund as well. That will be about $6 million..

Great, that's very helpful. Appreciate the detail. Then, lastly, going back to the dividend, I know you can't get too specific, and it's hard to predict what the Board will go with.

But is your thinking more along the lines of accelerating the annual growth? Or might it be more of a one-time step-up, either in 2015 or 2016 when your construction winds down?.

Again, I can’t tell, the Board will decide this. But I think our sense is that we want to continue to show growth in the divided over time and build into it rather than just do a big step function and then go back to the old numbers. But that’s something we’ll have to visit with the Board.

I clearly think they understand that we’re at the low end of the payout ratio as you look at this year and they understand the importance of the dividend and we’ll look at that. So, I can't give you any more specific guidance on that. But, we know we like to continue to grow the dividend and do that in a planful way so that we can sustain it..

Thank you..

Thank you. Our next question is a follow up from Paul Ridzon of KeyBanc Capital Markets. You may begin..

My question was answered. Thank you..

Hey Paul one other thing on decoupling, just to clarify it was the third quarter of 2014 that had a $6 million refund and year-to-date it’s about little over $3 million..

Thank you..

Thank you. I am showing no further questions at this time. I would like to turn the conference back over to Jim Piro for closing remarks..

Thank you. We appreciate your interest in Portland General Electric. And we look forward to meeting with many of you at EEI in November in Dallas. So, have a great day. Thanks..

Ladies and gentlemen, this concludes today's conference. Thank you for your participation. Have a wonderful day..