Good morning everyone. And welcome to Portland General Electric Company’s Fourth Quarter 2012 Earnings Results Conference Call. Today is Friday, February 22, 2013. This call is being recorded and as such all lines have been placed on-mute to prevent any background noise. After the speakers’ remarks there will be a question-and-answer period. (Operator Instructions). For opening remarks, I would like to turn the conference call over to Portland General Electric’s Director of Investor Relations, Mr. Bill Valach. Please go ahead, sir.

Thank you, Jim. Turning to slide 10, net income for the fourth quarter was $28 million and $0.38 per share, compared with the earnings in the fourth quarter of 2011. For the full year, net income was $141 million or $1.87 per share versus last year, when we earned the $147 million or $1.95 per share. Earnings are at the low end of our guidance due to warm weather and higher income taxes in the fourth quarter. These factors, along with increased pension expense were partially offset by deferrable cost related to four capital projects. Total retail revenues for the quarter were $445 million, down $18 million from the same period last year, driven by 2% decrease in customer prices and a 2% decrease in energy deliveries, as I mentioned, primarily due to warmer weather. These were offset by a combination of regulatory items netted out in depreciation. Annual retail revenue which was flat year-over-year were also affected by warmer weather and the customer price decrease. For the fourth quarter, weather adjusted energy deliveries were up 1.4%. This was driven by gains in all sectors led by industrial customers. For the full year, Weather adjusted energy deliveries were up 0.6% due to strong demand from high-tech, parts manufacturing and other industrial commercial customers. This growth in net energy efficiency reduced our annual growth by about 0.5%. For the fourth quarter, purchased power and fuel expense decreased to $22 million versus last year. For the full year, the decrease was $34 million with net variable power cost $17 million below the baseline, driven by low purchase power and natural gas prices. Since our regulated ROE was below 11%, we did not record a refund to customers under the Power Cost Adjustment Mechanism or PCAM. In 2011, power cost was $34 million…

Thank you. (Operator Instructions). And we will take our first question from Neil Mehta with Goldman Sachs.

Couple of quick questions here; first on D&A, did you not take the entire capital deferral in 2012? Curious way D&A ticks down in 2013 in the guidance.

We are taking the entire capital deferral. Our D&A adjust periodically and it has been influenced by a couple of items. One is if you see tax credits that we talked about in some prior calls and then also the Boardman accelerated depreciation which became effective in mid-2011 and increased customer prices about 1%. So overall it’s going to be about $4 million different, roughly in line with 2012.

And is $500 million of incremental growth cap ex associated with the 3 RFPs still the magic number before you would issue equity?

When we look at our financing; the $500 million are internally generated funds, the amount of additional equity we're able to create was a capacity for additional debt financing and as we look it sort of year in and year out, that number can fluctuate and we ended 2012 with a 51% equity ratio. So we have a little bit of wind to us, but we also try and make sure that our tiding with regards to all financing works well and provides the most flexibility.

And then lastly in your GRC filings from last week I felt that you are assuming 2% negative demand growth in the ‘13 filing. Can you reconcile that with that 0.5% to 1% view? Does your guidance from today exclude load margin industrial customers if that's the difference?

You know Neil that's a great question and one of the things that we have a difficult time with and have worked hard on is our low forecasting of our large industrial customers and certain of that risk that takes place in their operation. And so as an example we had a large paper company that ceased its operations at the end of December and in advance of those sorts of announcements we're not able to forecast exactly when those things will take place. So when we look at our guidance that's out of 0.5 to 1% for 2013, the total 2014 number that's in our rate case is essentially 1% higher than that. So whilst there's some ups and downs, the overall trends of growth in our area are consistent and as Jim mentioned we are seeing very strong industrial growth and continued in migration. So we feel very good about our load forecast.

Now we will take a next question from Lauren Duke with Deutsche Bank.

Can you comment on Cascade Crossing? You mentioned that $800 million for kind of full scope of the project. Can you give any sense of rough breakdown about how is that is the 120 mile line that you talked about that could start in 2017 versus some of the other projects, the substations and other pieces of that?

No, we really haven’t given that information out yet; we are still doing new designs, likely the line from the Coyote Springs area to new Pine Grove substation will be a single circuit line. So we are still not, redoing the estimates for the cost that, probably less than half but we are still working on final estimates. So it’s all part of the combined analysis that we’re doing based on the new MOU with Bonneville.

Okay and some of that, I guess the line you mentioned could start in 2017, could some of the other spending occur before 2017 or would it really build on the line?

Now there could be some investments ahead of time. That’s really based on the conversations we have been having with Bonneville and how we could optimize the system and looking at it from a single utility prospective. So there might be some investments ahead of the time but until we reach final agreements with Bonneville, I really can’t give any more detail on that.

And then one quick other question if I may. Can you quantify what the weather impact was for just fourth quarter and then for the full year as well?

Sure. The weather impact for the fourth quarter was roughly about $0.07 and for the full year was $0.14.

And we’ll now take our next question from Brian Russo with Ladenburg Thalmann.

Correct me if I am wrong but it looks like your ‘13 CapEx has increased about $100 million and I would assume that’s predominantly Port Westward 2?

Yes, that’s a lot of that includes Port Westward 2. We also have some additional spending of about $43 million in our base business. This includes a readiness center for disaster recovery and some other expenditures, largely in our distribution but also on our generation area.

Could you kind of just outline the spend for Port Westward 2 in ‘13, ‘14 and ‘15 given the first quarter ‘15 start date?

Sure. What we’re forecasting right now is about a $161 million this year, $107 million in 2014, and then $33 million in 2015.

And what is your AFUDC rate?

Right now it would be at the 8.33 rate, which is our combined debt equity rate and then what we do not accrue for the equity portion of that, we’re reflecting approximately $6 million in our guidance for 2013 for the AFUDC portion of Port Westward.

And, it’s my understanding that you guys don’t elect the honest depreciation because of all the PTCs you guys use right?

Each year we make a decision based on where we are, given the accelerate depreciation we have on our exciting wind farm, the amount of production tax credits to make sure that we make the best decision for customers and the company and utilize the maximum amount of opportunity that we have. We have most recently been at that maximum, have not recently elected honest depreciation. This next texture we’ll again take a look the analysis and make a decision. I’d right now we’re kind of on the fence as to whether we would elect it.

Because when - you filed your’14 test year of $3.1 billion and assuming all else equal should we add 300 million of net plan for Port Westward 2 to kind of gauge what ‘15 test year would look like?

I think that’s a fair assessment and the other would be, we do continue to have growth in our deferred tax assets. If you look between ‘11 to ‘12 we went up from just under $530 million to $588 million I think at the end of the year in deferred tax asset. So that will continue to grow as we maximize the tax opportunities that we have.

And lastly, I’m surprised that the total cost of the revised Cascade project of $800 million, I’m just curious what are the moving parts there? It looks like the line is cut in half but yet you’re adding substations and I’m just trying to get a better feel for what makes this $800 million?

It’s combination of companies. Obviously we took out a piece of the line that we would build from the Pine Grove area to Salem. So that’s reduction in cost but as part of the MOU our anticipation is that we would invest in certain projects with Bonneville Power Administration that would increase the flow on the southern part of their system, and so those investments that wouldn’t be in the exact transmission line but in other facilities that would increase the capacity on the Southern portion of Bonneville. So it is a combination of assets including the new substation of Pine Grove.

Is the line going to be a 230KV or is it going to be a 500KV?

It will be a 500KV line but likely single circuit from Coyote to the New Pine Grove Substation.

So basically $1 million a mile? $2 million to 2.5 million a mile?

Other typical numbers for mileage, but again, we haven’t disclosed that.

And we will now take our first question from Andrew Weisel with Macquarie Capital.

Few questions for you. First on the 2013 guidance, if I do kind of accrued back at the envelope of what the earned ROE is looking like, I get to a number in the ballpark of 9.2. Jim, I saw some quotes over the last weekend that without the help from the rate case you would be earning more like 5.9%. How can I reconcile those two?

So, in 2013 we have continued focus on O&M cost control to be able to manage through to a three year gap between rate cases, and as I noticed in the script, we have only had a couple percent increase over the entire turn since our last rate case. Unfortunately we just can’t maintain that level and we will continue in particular to see rising pension cost unless we are able to bring in to customer prices, the proposal that we have made. We also expect to have next year on the tax side; we won't have the $0.07 hit that we had this year for the change in deferred tax assets. And then also we continue to see some modest load growth, some return to more normal weather and some other items. So we are not able to seek recovery of these expenses on capital side, which I represented about 40% of our rate base request or the additional O&M expenses that will be coming into effect, then we would be at that number that Jim has quoted in the rate case about 5.5% to 5.7%.

We also have a couple of major capital projects, not major but capital projects coming into service in 2014.

Well, that’s reflected in the rate base outlook of 3.1, right?

It is and note that the 3.1 rate base has also reduced because of the deferred tax assets that we’re continuing to build.

The difference is in 2013 we’re booking AFUDC on those projects where in 2014 we have put into rate base.

Yes.

Now a just few on the growth projects. First with the peak at Port Westward 2, why didn’t you vet the shortlist with the regulators? I understand that you kind of worked with an independent evaluator and decided that Port Westward 2 was the winner, but I’m just curious why not go through the process of vetting that with regulators before you start construction and do you see any potential risk that you won’t be able to recover some of that spending down the road?

So we went through a very exhaustive RFP process and allowed all the bidders to provide information around their bids. The process went for over 12 months and those bids were becoming stale as of January 31st. So we really needed to move forward to capture the economics of those projects before those bids became not valuable to us in terms of being able to execute. So that was one consideration. The independent evaluator watched over the process and we’ve done this before in prior proceedings. They’ve made sure the process was fair and reasonable and they concluded that we had a good shortlist and so we saw no additional reasons to ask for acknowledgement, which would slowdown the process and not be able to capture the value of those bids that were put in. And we never have to asked for acknowledgement in the RFP processes before. So we felt like we’ve followed the process, we had good report from the independent evaluator and based on that we decided to go forward.

Okay fair enough and on the base load one, it says the shortlist include PPAs and PGE ownership and you’re beginning negotiations with the top bidder. I’m sure it’s tough to get in detail, can you add any color where the PGE proposed plan lies in the shortlist, whether it’s something that is still a likely contender if negotiations don’t go well or how we kind of think about possible outcomes around that?

No, this has to be a very confidential process and we can’t release any information during the negotiations process.

Understood, I had to at least try and then my last question on Cascade Crossing, the construction obviously pushed back a couple of years. You mentioned that some things could come sooner but for the main line just curious on the timing, why isn’t the construction expected to start until 2017 and I’m not bit sure Obama would call that rapid response if it’s going to be so for out.

I can tell you building transmission projects are challenging to go through all the processes and environmental permitting and so forth. We figured a bridging strategy to give us some time to get the project built. We want to work with Bonneville on the right integration of this project in the grid. I think we are really pleased that we have found a single utility solution that really reduces impacts on the environment and in that light I think everyone is willing to take a little more time to get it done right and make sure that we get the best value for all customers in the region.

And we will now take our next question from Sarah Akers with Wells Fargo

Given that Port Westward is going online in the quarter after your ‘14 test year, what are your current thoughts around the strategy and timing of recovery of that investment?

The project will go in, in early 2015, so it will be after the 2014 test year. So we will look at either a couple option, one is either file a general rate case for 2015 to include Port Westward 2 into your revenue requirements or there is some possibility we could just update our 2014 test year and just incrementally include Port Westward. So those are two viable options. As we move forward and look at our cost structure for 2015 and have conversations with the regulator we’ll decide which of those passes the most optimum for both our customers and the company. We will have to file a rate case for 2015 again early in 2014, but we’ll have to have some visibility on how we are going to do that. So we have some time to make that decision. Much of that will be predicated on what we think O&M cost are for 2015 as well as what the load growth in 2015 look like. So we have a couple of options there. We will make that decision as we go through this year and if we decide to file a general rate case for 2015 we would do that in early February of 2014.

And when you say just update the 2014 test year, could you do that in the current rate case process, or would that be outside of this rate case, didn't quite understand that offset.

It would be outside of this rate case, it would be something we file next year in 2014 and again we could either layer Port Westward on to the 2014 approved test year as just an incremental change for determining appropriate prices or just file a new test year for 2015.

Okay so you wouldn’t necessarily have to open it up to a general rate case. You could kind of go in on a single item with one specific update?

Those are options. We have to really talk with the folks and the consumer groups would want to make sure that 2015 looks okay. So we are going to have to be some demonstration but rather than going through an exhaustive rate case, if we’re only just going to ask for that incremental change, as long as we can demonstrate that our prices are currently just and reasonable, we may not have to do that. But I think for you to assume that we file a general rate case is probably the safe assumption here. If we can find another way to get at it, we'll look at that.

And then in the past we thought about a structural regulatory lag of around a 100 basis points. Is that still a reasonable expectation in the first year of new rates in '14, or is there any reason that we should see that lag start to compress in this next rate case.

So Sarah, I think for forecasting purposes for your financial models and what not, I would continue to use the 1%. As we continue to close the gap on our rate base, I think that that will shrink over time but in the near term I think the 1% is a safe number.

And we'll take our next question from Michael Bates with DA Davidson.

I wanted to ask one more follow up question to the cascade crossing issue if I could. In the past you had characterized the project as a potential partnership with one partner being Pacific Corp. Is that still a possibility under the modified plan that you're talking about?

Yes, we're trying to secure about 2,600 MW for this new MOU plan with Bonneville. Pacific Corp still has an interest in about 600 average megawatts of that line and so we are still in conversation with Pacific Corp. I think they want to see us get a little further down the road on the MOU or the agreements with Bonneville. But they still have an interest in the lines to serve load in the southern part of their service territory in Oregon.

And do you have any expectations as far as when this moves beyond the MOU stage?

Well, we're starting right now the negotiations with Bonneville towards a definitive agreement, doing planning studies and just looking at all parts of the structure of the agreement. It's probably going to take us a good six months to really get clarity on that definitive agreement and get it lined out. So that's kind of our timing.

All right, thanks, also any color on expected effective tax rate in 2013.

Sure, what I would use for modeling purposes would be sort of the average of the last four years. I noted that we had just over a 28% rate in 2011 and that was actually a low for us, while 2012 was a high at just under 31.5. Overall over the last four or five years we've averaged about 30%.

The big wildcard there is obviously the production tax credits with our wind farms and that really swings that rate. We have a marginal rate but then that impacted by the PCCs and the amount of wind generation we expect to receive.

That’s also one of the things that contributes to the seasonality of the tax rate moving around between the quarters.

And we will take our next question from Maurice May with Wellington Shields.

Couple of questions. First of all getting back to Cascade Crossing, with Pacific Corp still in the picture; is it possible that they would invest 20% to 25% of that $800 million estimate?

Yes, if you take 600 over 2600, that’s a rough range of where they might be. They are looking for bilateral capacity. So that percentage might go up a little bit. If we can fix here the full 2600, that’s what it would look like.

Okay and on the name Cascade Crossings, since your line will not be crossing the Cascades any more, is the name going to be changed?

Great question, we haven’t really got there. We are still trying to get a path. I think the bottom line is that we are trying to create a pass across the Cascades and at the end of the day what we will end up is with assets and rights and we will end up with a transmission path that hopefully will give us a full path across the Cascade.

Okay good and my second question has to do with hydro. Can you review the hydro year to date, the snowpack to date and the possible impact on PKM in 2013?

The runoff forecast was in the 10-K but as I look at it here, this is as of February 18th, it’s 89% on the Columbia River at the Dalls, which includes the Columbia Columbia River as well as the Snake River. The mid-Columbia Grand Coulee which feeds our mid-Columbia contract is about 90%. The Clackamas River at Estacada which is our west side project was about 98% and the Deschutes, which is our Pelton Roundview project is about 92%. Now this is still early in the year in terms of the run off forecast and even though these are below normal, we have seen heavy snowfalls in March that can change these numbers. So, that’s why we mentioned in our guidance we are still assuming normal hydro. When we get to the end of the March or clearly in the second quarter, first quarter earnings call we will have better clarity on what the hydro looks like but right now it’s slightly below normal.

And we take our next question from John Alley with Decade Capital.

This is a follow up to Brian Russo's question regarding the deferred tax assets. Maria, you said those would flow in from ‘14 to ‘15?

No. So, let me explain a little bit better. What we did was our state tax composite rate changed by little bit less than 1%. That will continue going forward and is reflected in our guidance. What will not continue is the one time balance sheet adjustment to deferred taxes that resulted in the majority of the change and the higher rate in 2012. So, if you think about ‘12 to ‘13 numbers, we’ll pick up about $0.07 a share on a tax line as we are forecasting 2013.

I meant the deferred taxes, as relative to the rate base growing?

Yes. The deferred taxes will continue to grow as we maximize the amount of depreciation that we’re taking. Remember, we’ve invested a lot already in wind farms when we take accelerated depreciation on those. We also have production tax credits.

Okay. So, when I think about the ‘14 rate base being $3.1 billion and then to Brian’s question, do we just add Port Westward 2 on top of that to kind of come up with proxy for ‘15; what I guess is the start that we should be reducing that by for the deferred taxes?

Yes. What we forecast in the rate case is about a $150 million. About a third to 40% is already reflected in the 2012 numbers. So you can add about another $60 million and it’s in the testimony, it roughly equals about the same.

So that would an additional $60 million reduction in ‘15. Is that the way to think about that?

Yes, exactly. Yes.

Okay. And the primary reason from the reduction from ‘12 to ‘14, was that solely deferred taxes?

Yes. Offset by normal increases in capital expenditures. Excluding Port Westward 2, our capital expenditure amounts are still growing.

Okay. But we can assume that ‘15 will still be up, but just not by the full amount of Port Westward from the 3.1.

Exactly. Yes.

And then just to be clear, so on $0.14 of weather in ‘12, that was versus normal?

That was versus last year and versus normal, let me get that one for you. Versus normal it is, 2011 in the first quarter was particularly cold and so over versus normal, it would really be about a $0.04 would be the delta.

In '12 versus normal?

Yes.

And we will take our first question from Andy Levi from Avon Capital.

Just a couple of questions. On the renewal bid, I guess it’s possible from what I have read that it could end up being an existing asset that you may end up purchasing, and I know you cannot comment on that. But if that where the case, how would that work, regulatory wise? Is there some type of mechanism that makes it easy for you guys to get in the rate base?

Yes, we have a renewable adjustment caused price mechanism that allows us to track in, renewable resources in the year that they come into service through deferred account and then they go into customer's prices, the following year. We typically make that filing in April and then it is deferred accounting for the current year and then goes into current prices the following year. So, we do have a mechanism if there is an existing asset selected. And if it happens to be a contract then we do annual updates of power costs and would go through the annual update tariff or in the case of our current rate case that would get updated into our power cost forecast.

So that makes I guess the financing of it a bit easier, as far as how that affects earnings and then the drag from that.

Yes, there is no lag that way.

It eliminates any drag.

Perfect, and then on the energy piece, I just want to make sure I understand, the winning bid at this stage, is that possible, that that’s a build and buy or is that not a build and buy?

As we said in our, it could either be a purchase power contract or it could be an ownership option for PGE. Obviously you can tell from this, our benchmark did not win the bid or if you would have announced it. So we are in negotiations with the top bidder and if and when we get to the finish line with that bidder then we would disclose the results of the bid.

But one of the possibilities is they build, you buy. Is that correct?

That’s a possibility.

Right, and I guess in some ways that’s a better scenario as far as again, regulatory lag because you wouldn’t have to put any capital out until obviously the thing was built.

It depends on the structure of the agreement and it could go either way. It could be one where they build and we buy at the end or we make progress payments if that was the option that was selected.

And we’ll take our next question from Steve Mars with Citizen’s Trust (ph).

You gave indication of the weather impact for the fourth quarter of last year as well as the full year. Now for your 2013 earnings guidance, is there a portion of that guidance affected by weather?

Yes, in terms of our guidance, loads are effected by two different things. One is weather and we use a normal weather forecast. So that would be returning back to what are sort of our long term historical levels and that difference or pickup would be about $0.04. We also have forecasted load growth of about 0.5% to 1%. So that would also impact that line.

So the net of it is about a $0.04 estimate backed into your $1.85 to $2 earnings guidance for this year?

Yes, as is the load forecast growth that we have.

Again, that’s over 2012 results but for 2013 we are assuming normal weather in the forecast.

(Operator Instructions). And we’ll take our next question from Andy Levi with Avon Capital.

One last question I forgot to ask, on the AFUDC guidance that you gave for this year, I guess it’s $160 million that you’re going to spend on the PW2, right, this year? Is that how I should understand it?

Yes.

But I guess, I had a lower whatever, we didn’t know what the numbers were but just looking at the AFUDC. I guess that’s not a full year of AFUDC on the 161, is that?

No, absolutely, because we spend incrementally as the construction takes place when we make payment for equipment. So most of our AFUDC is actually back end loaded.

Okay, so that $6 million is a portion of, I guess in some ways to 161. So we will see a kind of show up also in 2014 plus whatever incremental spend you have in 2014.

Exactly.

And that concludes today’s question-and-answer session. Mr. Piro, at this time I’ll turn the conference back over to you for any additional closing remarks.

Thank you all. We appreciate your interest in Portland General Electric and invite you to join us when we report our first quarter 2013 results in May. Thanks a lot and have a great day.

And ladies and gentlemen, that concludes today’s conference call. We thank you for your participation.