Portland General Electric Co (POR) 2012 Q4 法說會逐字稿

Good morning, everyone, and welcome to the 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, Brian, and good morning, everyone. We're pleased that you can join us today. Before we begin our discussion this morning, I'd like to remind you that we have prepared a PowerPoint presentation to supplement our discussion today, and we'll be referring to slides throughout the call. For those of you accessing the call over the phone, these slides are available on our website, at www.portlandgeneral.com.

Referring to slide 2, I'd also like to make our customary statements regarding Portland General Electric's written and oral disclosures and commentary. There will be statements on 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-Qs. The Form 10-K for the year-end 2012 is available on our website, at www.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 the Safe Harbor statement should be incorporated as part of any transcript of this call.

Portland General Electric's fourth quarter and full year earnings were released before the market opened today, and the release is available on our website, at www.portlandgeneral.com. Leading our discussion today are Jim Piro, President and CEO, and Maria Pope, Senior Vice President of Finance, CFO and Treasurer. Jim will begin today's presentation by providing a review of our performance in 2012 and an update on our strategic capital projects. Then Maria will provide more detail around the quarterly and annual results, our expectations for 2013, and our 2014 general rate case filing. Following these prepared remarks, we will open the lines up for your questions. And it's now my pleasure to turn the call over to Jim.

Thanks, Bill. Good morning and thank you for joining us. Welcome to Portland General Electric's 2012 fourth quarter and year-end earnings call. As slide 4 shows, on today's call I'll provide an overview of our financial and operating performance, give an update on the economy in our operating area, and discuss the progress on our strategic initiatives. Then Maria will provide a financial update, discussing PGE's fourth quarter and full year results, as well as our recently filed general rate case and outlook for 2013. So let's begin.

As you can see on slide 5, PGE's net income was $28 million, or $0.38 per share, for the fourth quarter of 2012, and $141 million, or $1.87 per share, for the full year. We are initiating full year 2013 earnings guidance of $1.85 to $2.00 per diluted share.

Now on to operational excellence on slide 6. We continued to deliver excellent operating performance in 2012. PGE's delivery system and generating facilities operated extremely well, with the average duration and frequency of outages being low and in the top quartile. Our generating plants' availability factors were better than our goals. In regard to overall customer satisfaction, PGE's ratings remain strong. We are the top investor-owned utility in the nation for residential customer satisfaction and number one in the West for general business customer satisfaction, according to JD Powers and Associates. PGE also ranks second nationally for large key customer satisfaction in the TQS Research survey.

I'm also pleased with the results we're seeing from our benchmarking and best practices work. We've been leveraging technology and implementing new systems in several areas of the Company, including Transmission and Distribution, Human Resources, and Finance and Accounting. These changes are helping us create efficiency, improve processes and reduce costs, which is important in our efforts to keep customer prices as low as possible in the face of growing regulatory and inflationary costs. I'd like to take this opportunity to recognize the hard work and dedication of our employees, who have helped us maintain excellent service to our customers.

Now let's move on to slide 7 for the economic outlook in our operating area. We're seeing continued growth, particularly in the high tech sector and manufacturing sector. In the second half of 2012, Intel and Nike announced significant expansion plans in our service area; and while the solar industry's environment continues to be challenging, it's more than offset by growth in the high tech and data centers. We're also encouraged by recent labor statistics. The unemployment rate in our operating area averaged 7.4% in December, 2012, down from 7.9% in 2011. The improving housing market, along with Oregon's continued second in the nation ranking for in-migration helped PGE add customers in 2012. Weather-adjusted 2012 energy deliveries are up about 0.6% over 2011 levels, driven primarily by the industrial sector, which grew about 2%. For 2013, we are expecting weather adjusted growth of 0.5% to 1%, net of energy efficiency.

Now please refer to slide 8 for an update on our progress executing our IRP action plan. We're nearing the completion of rigorous RFP processes, and I will cover where we are with the four types of resources we are seeking. First, capacity. Our Port Westward Unit 2 natural gas plant was selected to meet our flexible capacity need. This new 220-megawatt natural gas fueled plant is designed for maximum flexibility, to integrate growing renewable energy resources and serve as a peaking resource during periods of high customer demand. The plant is expected to cost between $300 million and $310 million, excluding the allowance of funds used during construction, and will create up to 200 construction jobs in the area. The in-service date is currently slated for the first quarter of 2015.

In regard to both our seasonal peaking resource and our energy resource, negotiations are currently underway with the top bidders and we expect to announce the outcome by mid-year. The bids on the energy resource final short list include both purchase power agreements and PGE ownership options. The capacity and energy RFP process has been thorough, and we are pleased that the independent evaluator representing the Oregon Public Utility Commission confirmed that the RFP was conducted in a fair, unbiased and transparent manner.

And now, renewables. As you can see on slide 9, we received 64 bids, representing 39 distinct generating projects with a combined nameplate capacity of 4,450 megawatts, for our renewable RFP seeking 100 average megawatts. These include a mix of projects to be sold to PGE pursuant to an asset purchase agreement, projects that would sell power to us under a long-term power purchase agreement, and PGE's benchmark bid. The independent evaluator is also evaluating these bids and is scheduled to release their report on this RFP process next month. We expect final resource selection to occur by mid-year.

Now on to Cascade Crossing. In January, we signed a memorandum of understanding with Bonneville Power Administration agreeing to pursue a phased in and integrated approach to achieving PGE's transmission goals. The original Cascade Crossing line would be shortened from 215 miles to approximately 120 miles and would run from Boardman to central Oregon. Construction would take at least two years and could start as early as 2017. In addition, PGE would build at least two substations, install series capacitors to boost capacity of existing lines, make other transmission investments in the Portland and Salem areas, and explore the possibility of asset exchanges and other potential transmission opportunities to deliver up to 2,600 megawatts to customers.

We expect the cost of the overall modified project to be more than $800 million. This collaborative regional solution would avoid most impacts to two national forests, private forest and agricultural land, and a tribal reservation. It has been received positively by President Obama's rapid response team for transmission, as well as other stakeholders. As we continue negotiations with BPA, we will update the expected timing and estimated cost. We are focused on delivering the least cost, least risk solutions to provide reliable power to our customers.

Now I'd like to turn the call over to Maria Pope, our Chief Financial Officer, to go into more depth on our financial and operating results. She will also discuss our general rate case, which we filed last Friday, and provide details on our guidance for 2013.

Thank you, Jim. Turning to slide 10, net income for the fourth quarter was $28 million, and $0.38 per share, comparable to 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 $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 the deferral of costs 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 a 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 revenues, which were 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 and commercial customers. This growth in net energy efficiency, which reduced our annual growth by about 0.5%.

For the fourth quarter, purchased power and fuel expense decreased $22 million versus last year. For the full year, the decrease was $34 million, with net variable power costs $17 million below the baseline, driven by low purchased 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 costs were $34 million below the baseline and we recorded a modest customer refund. Generation from PGE-owned and mid-Columbia hydro projects in 2012 were 11% above normal, but 27% less than 2011. Generation at our Biglow Canyon wind farm also decreased, about 7% from last year. Lower than expected wind generation also reduced our production tax credits, or PTCs, in both 2011 and 2012.

Moving on to slide 12, production, distribution and administrative costs totaled $114 million this quarter, equal to the fourth quarter of 2011. For the full year, O&M expense was $427 million, in line with guidance. This is $8 million higher than 2011, primarily due to a $7 million increase in pension expense. Depreciation and amortization for the full year was $248 million, and this reflects a $21 million increase over 2011, due to capital additions, several regulatory items I mentioned earlier, offset by the deferral of costs related to four capital projects. Income taxes increased $6 million year-over-year, as our effective tax rate in 2012 was 31.4% versus 28.3% a year ago. Lower wholesale sales in the state of Washington, which has no state income tax, resulted in an increase to our composite state tax rate and led to a $5 million reevaluation of deferred taxes. We filed for regulatory recovery of the deferred tax balance in January and are awaiting a response from the OPUC.

Now on to slide 13, as Jim mentioned, we filed a general rate case last Friday with a 2014 test year. If approved, the average overall price increase on January 1, 2014, would be about 6%. Our filing includes an ROE of 10%, a capital structure of 50% debt and 50% equity; and the overall revenue increase is $105 million, approximately 40% of which -- of the request covers capital additions and 60% covers operation and maintenance expenses. These include capital investments in generation and information technology; pension, health and wellness expenses; updated wind capacity factors to reflect actual history; plant operations and maintenance expense; and regulatory requirements, including critical infrastructure protection.

Jim also noted our 2013 guidance of $1.85 to $2.00 per share. As you can see on slide 14, this range is based on load growth of 0.5 to 1% over weather-adjusted 2012 levels, reflecting growth in the commercial and industrial sectors, normal hydro and plant operations and wind generation more closely reflecting historical performance, O&M for the year between $440 million and $460 million. This range includes $10 million increase in pension expense year-over-year and a $10 million, or 2%, annual increase in inflationary expenses. Also included are depreciation expense of $244 million and continuation of capital deferral, capital expenditures of $514 million, and approximately $6 million in non-cash AFUDC for Port Westward Unit 2. Our guidance does not include capital expenditures or AFUDC for any of the other RFP projects.

Now on to slide 15. We continue to maintain a solid financial position, including investment grade credit ratings and strong liquidity. Capital expenditures were $93 million in the fourth quarter of 2012 and totaled $310 million for the year. In the fourth quarter, PGE's revolving credit lines increased from $660 million to $700 million. As of December 31, we had $628 million in liquidity and were at an equity ratio of 51%. At this time, we expect to fund the construction of Port Westward Unit 2 with internally generated funds and debt. The need for any equity financing will depend primarily on the outcome and timing of the energy and renewable RFPs and Cascade Crossing. Jim?

Thank you, Maria. Our performance in 2012 reflects our employees' hard work and dedication. We are looking forward to continued progress on our strategic initiatives in 2013, including selecting energy and renewable resources, reaching a definitive agreement on Cascade Crossing, and completing the 2014 general rate case.

Before we open the call for questions, I'd like to update you on some changes in responsibilities for two members of PGE's officer team that were announced today. In my continued efforts to broaden the experience of the officer team, while still meeting our commitment to operational excellence and business growth, I'm pleased to announce that effective March 1, Maria will be taking on responsibility for all our generating plants, power supply operations and resource strategy. J

im Lobdell, who is currently Vice President of Power Operations and Resource Strategy, will succeed her. Jim has been with the Company almost 30 years and during his tenure has served in a number of financial roles. He became an officer in 2001, and in his current role he has been instrumental in meeting our customers' energy needs, planning for our energy future, and bringing to completion energy capacity and renewable RFPs that are critical to meeting our customers' energy needs. I want to thank Maria for her many contributions in the CFO role and look forward to working with both Jim and Maria in their new roles. Now, Operator, we're ready to open the call for questions.

Thank you.

(Operator Instructions)

And we'll take our first question from Neil Mehta with Goldman Sachs.

Good morning. Maria, congratulations on your new role, and Jim Lobdell, looking forward to working with you more.

Thank you.

Thank you.

Couple of quick questions here. First, on D&A. Did you not take the entire capital deferral in 2012? Curious why D&A ticks down in 2013 on the guidance.

We are taking the entire capital deferral. Our D&A adjusts periodically, and would have been influenced by a couple of items. One is the tax credits that we talked about on 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.

Got it. And is $500 million of incremental growth CapEx associated with the three RFPs still the magic number before you would issue equity?

You know, when we look at our financing, the $500 million are internally generated funds, the amount of additional equity we're able to take on -- create was a capacity for additional debt financing. And as we look at it 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 timing with regards to all financing works well and provides the most flexibility.

Got it. And then lastly, in your GRC filing from last week, I saw that you're 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 low margin industrial customers? Is that 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 load forecasting of our large industrial customers and certain event risk that takes place in their operations. 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 while there's some ups and downs, the overall trends of growth in our area are consistent. And as Jim mentioned, we're seeing very strong industrial growth and continued in-migration. So we feel very good about our load forecast.

Okay. All right. Thank you.

Thanks, Neil.

And we'll take our next question from Lauren Duke with Deutsche Bank.

Good morning.

Hello, Lauren.

Hello. Can you comment on Cascade Crossing? You mentioned the $800 million for the full scope of the project. Can you give any sense of rough breakdown about how much of 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're still doing new designs. Likely the line from the Coyote Springs area to the new Pine Grove substation will be a single circuit line. So we're still redoing the estimates for the cost of that. Probably less than half, but we're 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?

No. There could be some investments ahead of time. That's really based on the conversations we've been having with Bonneville and how we could optimize the system, looking at it from a single utility perspective. So there might be some investments ahead of time. But until we reach final agreements with Bonneville, I really can't give you any more detail on that.

Okay. Great. 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.

Okay. Great. Thank you.

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

Hello. Good morning.

Good morning, Brian.

Correct me if I'm wrong, but it looks like your '13 CapEx has increased about $100 million. And I would assume that that's predominantly Port Westward 2?

Yes. 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 in our generation area.

Could you 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 $161 million this year, $107 million in 2014, and then $33 million in 2015.

Okay. Great. And what is your AFUDC rate?

Right now it's at -- 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.

Okay. And it's my understanding that you guys don't elect bonus depreciation because of all the PTCs you guys use, right?

Each year we make a decision based on where we are, given the makers accelerated depreciation we have on our existing 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, and have not recently elected bonus depreciation. This next tax year, we'll again take a look at the analysis and make a decision. I'd say right now we're kind of on the fence as to whether we would elect it.

Okay. Because 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 gauge what '15 test year would look like?

Yes. 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 end of the year in deferred tax assets. So that will continue to grow as we maximize the tax opportunities that we have.

Okay. Great. 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 trying to get a better feel for what makes this $800 million.

So it's a combination of a couple things. Obviously, we took out a piece of the line that we would build from the Pine Grove area to Salem. So that's a 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 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's a combination of assets, including the new substation in Pine Grove.

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

It will be a 500 KV line, but likely single circuit from Coyote to the new Pine Grove substation.

So basically, $1 million a mile -- I'm sorry, $2 million to $2.5 million a mile?

Yes. Those are typical numbers for mileage, but again, we haven't disclosed that.

Okay. Thank you very much.

And we'll now take our next question from Andrew Weisel with Macquarie Capital.

Hello. Good morning, and congratulations again to Maria and Jim on the new roles. A few questions for you. First, on the 2013 guidance, if I do a crude back of the envelope of what the ROE -- 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 last weekend that without the help from the rate case, you'd 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've only had just a couple percent increase over the entire time since our last rate case. Unfortunately, we just can't maintain that level, and we will continue, in particular, to see rising pension costs, unless we're able to bring into 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 if we're not able to seek recovery of these expenses on the capital side, which are 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's quoted in the rate case of about 5.5%, 5.7%.

Okay. Thank you.

We also have a couple 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. Note that the 3.1% rate base is also reduced because of the deferred tax assets that we're continuing to build.

Okay.

The difference is, in 2013 we're booking AFDC on those projects, where in 2014 we'd have to put them into rate base.

Yes.

Got it. Now just a few on the growth projects. First, with the peak at Port Westward 2. Why didn't you vet the short list with the regulators? I understand that you worked with the 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 of 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 31. 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 made sure that the process was fair and reasonable, and they concluded that we had a good short list. And so we saw no additional reasons to ask for acknowledgement, which would have slowed down the process, and not be able to capture the value of those bids that were put in. And we never have asked for acknowledgement in the RFP processes before. So we felt like we followed the process. We had a good report from the independent evaluator. And based on that, we decided to go forward.

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

No. (Laughter) We have to be fairly -- this has to be a very confidential process, and we can't release any information during the negotiations process. So, that's where we stand.

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 some 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 quite sure Obama would call that rapid response, if it's going to be so far out.

All I can tell you is building transmission projects are challenging to go through all the processes and environmental permitting and so forth. We've 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're really pleased that we have found a single utility solution that really reduces impact on the environment. And in that light, I think everyone's 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.

Okay. Thank you very much.

And we'll now take our next question from Sarah Akers with Wells Fargo.

Hello. Good morning, everyone.

Good morning, Sarah.

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?

So 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 options. One is either file a general rate case for 2015 to include Port Westward 2 into our revenue requirements. Or there is some possibility we could update our 2014 test year and incrementally include Port Westward 2. 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 paths is the most optimum for both our customers and the Company. We'll have to file a rate case for 2015, again early in 2104, but we'll have to have some visibility on how we're 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 costs are for 2015, as well as what the load growth in 2015 look like. So we have a couple options there, and we'll 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? I don't quite understand that option.

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 onto the 2014 approved test year as 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 go in on a single item with one specific update?

Those are options. We'd have to really talk with the folks. And the consumer groups would want to make sure that 2015 looks okay. So we're going to have to do some demonstration. But rather than going through an exhaustive rate case, if we're only going to ask for that increment change, as long as we can demonstrate that our prices are currently and reasonable, we may not have to do that. 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.

Got it. And then, in the past we thought about a structural regulatory lag of around 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 whatnot, 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.

Great. Thanks a lot.

Thanks, Sarah.

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

Hello. Good morning. 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 PacifiCorp. Is that still a possibility under the modified plan that you're talking about?

Yes. You know, we're trying to secure about 2,600 megawatts for this new MOU plan with Bonneville. PacifiCorp still has an interest in about 600 average megawatts of that line, and so we are still in conversations with PacifiCorp. I think they want to see us get a little farther down the road on the MOU, or the agreements with Bonneville. But they still have an interest in the line 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 the definitive agreement, doing planning studies, and looking at all the parts of the structure, the agreement. You know, 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 our timing.

All right. Thanks. Also, any color on an expected effective tax rate in 2013?

Sure. What I would use for modeling purposes would be the average of the last four years. You know, 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 wild card 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's impacted by the PTCs and the amount of wind generation we expect -- or receive.

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

Thank you very much.

And we'll take our next question from Maury May with Wellington Shields.

Yes. Good morning, folks, and congratulations, Maria.

Thank you.

We're going to miss you. A couple questions. First of all, getting back to Cascade Crossing. With PacifiCorp 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 2,600, that's a rough range of where they might be. They're looking for bilateral capacity, so that percentage might go up a little bit. So that would be -- if we can consider the full 2,600, that's what it would look like.

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

(Laughter) Great question. We haven't really got there. We're still trying to get a path -- I think the bottom line is, we're trying to create a path across the Cascades. And at the end of the day, what we'll end up with assets and rights, and we'll end up with a transmission path that hopefully will give us a full path across the Cascades.

Okay. Good. And my second question has to do with hydro. Can you review the hydro year to date, the snow pack to date, and the possible impact on PCAM in 2013?

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

Okay. Good. Thank you, Jim.

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

Good morning, guys.

Hello, John.

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. Let me explain a little bit better. What we did was our state tax composite rate changed by a 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 we will pick up -- if you think about '12 to '13 numbers -- we'll pick up about $0.07 a share on the tax line, as we are forecasting 2013.

I meant the deferred tax -- 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 and 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 come up with a proxy for '15, what is the stub that we should be reducing that by for the deferred taxes?

Yes. What we've forecast in the rate case is about $150 million. About one-third to 40% is already reflected in the 2012 numbers. So you can add in -- yes, you can add about another $60 million. And it's in the testimony. It roughly equals about the same.

So that would be 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. So we can assume that '15 will still be up, but just not by the full amount of Port Westward?

Exactly.

From the 3.1%?

Yes.

Okay. Great. And then just to be clear, on the $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 -- last year in the first quarter was particularly -- 2011, in the first quarter was particularly cold. And so over versus normal, it would really be about $0.04 would be the delta.

In '12 versus normal?

Yes.

Great. Thank you so much.

We'll take our next question from Andy Levi with Avon Capital.

Hello. Good afternoon. Or I guess good morning, for you guys.

Good morning, Andy.

And congratulations, Maria.

Thank you.

Just a couple questions. On the renewable bid, I guess it's possible, from what I've read, that it could end up being an existing asset that you may end up purchasing. And I know you can't comment on that. But if that were the case, how would that work regulatory-wise? Is there some type of mechanism that makes it easy for you guys to get it in the rate base?

Yes. We have a renewable adjustment clause mechanism that allows us to track in renewable resources in the year that they come into service through deferred accounting, and then they go into customer prices the following year. We typically make that filing in April, and then it's 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. There's also -- and if it happened to be a contract, then we do annual updates of power costs and it would go through the annual update tariff, or in the case of our current rate case, it would get updated into our power cost forecast.

That makes, I guess, the financing of it a bit easier, as far as how that affects earnings and the drag from that, where it --

Yes. That really -- there's 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 else we would have announced it. So we are in negotiations with the top bidder, and once we -- 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. 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 and --

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

Okay. Great. That answers both my questions. Thank you very much.

Thank you.

And we'll take our next question from Steve Marrs with CitizensTrust.

Good morning, all.

Good morning, Steve.

Good morning. 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, please?

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

So the nut of it is about a $0.04 estimate baked into your $1.85 to $2.00 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.

All right. All right. Thank you very much.

Thank you.

(Operator Instructions)

Okay. I think that's all the -- oh, we got one more question. So we'll take the last question and then we'll wrap it up.

And we'll take our next question from Andy Levi with Avon Capital.

Sorry, guys.

Hello, Andy.

I know you guys were on your way home. Sorry about that. (Laughter) But 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 new asset, right, on the PW2, this year? Is that how I should understand it?

Yes.

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

No. Absolutely. Because we spend incrementally as the construction takes place or we make payments for equipment. So most of our AFUDC is actually quite back-end loaded.

Okay. So that $6 million is a portion of, in some ways, the $161 million. So we'll see it show up also in 2014, plus whatever incremental spend you have in 2014. Is that correct?

Exactly. Yes.

Perfect. That answers my question. Thank you.

Thank you.

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 or 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.