埃克西爾能源 (XEL) 2014 Q4 法說會逐字稿

Good day, everyone. Welcome to the Xcel Energy fourth quarter 2014 earnings call. Today's call is being recorded. At this time I would like to turn the conference over to Paul Johnson, Vice President of Investor Relations. Please go ahead.

Good morning, and welcome to Xcel Energy's 2014 fourth quarter earnings release conference call. Joining me today are Ben Fowke, Chairman, President, and Chief Executive Officer; and Teresa Madden, Executive Vice President and Chief Financial Officer. In addition, we have other members of the management team in the room to answer questions if necessary.

This morning we will review our 2014 full year results, reaffirm our 2015 earnings guidance range and update you on strategic plans and business that relate to business and regulatory developments. Slides that accompany today's call are available on our webpage. In addition, we will post a brief video on our website of Teresa summarizing our financial results later this morning.

As a reminder, some of the comments during today's conference call may contain forward-looking information. Significant factors that could cause results to differ from those anticipated are described in our earnings release and our filings with the SEC.

I will now turn the call over to Ben.

Thank you, Paul, and good morning. I am going to start by highlighting some of the key successes of 2014 and update you on some exciting developments at Xcel Energy. Teresa will provide more detail on some of these items. 2014 was another strong year for Xcel Energy as the Company reported earnings of $2.03 per share. This marks the tenth consecutive year we have met or exceeded our earnings guidance, and the fifth consecutive year we've delivered earnings in the upper half of our guidance range.

In addition, we raised our dividend for the 11th year in a row. From a regulatory perspective, we made significant progress wrapping up rate cases in Wisconsin, New Mexico, and Texas. We received a constructive ALJ recommendation in Minnesota, and most recently, reached a favorable three-year settlement in our Colorado electric case.

When we filed the case in Colorado we stated that our objective was to establish a multi-year regulatory plan that provides certainty for PSCo and its customers. This settlement accomplishes that goal and provides us a reasonable opportunity to earn our authorized return in our Colorado electric business over the next three years.

From an operational perspective, I also wanted to take a moment to say how incredibly proud I am of the efforts of our employees this year. We hit record levels of safety in 2014, improving for the seventh straight year. And, again, we demonstrated our top tier operating performance with industry-leading reliability scores.

Recall last quarter we unveiled our refreshed strategic plan that was focused on improving utility performance, including the goal of closing the ROE gap by 50 basis points, and increasing the amount of revenue generated from long-term regulatory agreements. Driving operational excellence by focusing on limiting annual increases in O&M costs to between 0% and 2%; providing our customers more options and solutions; and, finally, investing for the future by focusing on incremental growth opportunities in our natural gas and transmission businesses.

Today we are excited to update you on the progress we have made on some of these initiatives. The electric utility industry is in the midst of a major transition and we are committed to being on the front end of this change. We will be a leader in the say way we proactively implemented our environmental strategy over a decade ago. To this end we are pursuing regulatory changes to better align with the clear direction that customer preferences, federal policies, and state initiatives are moving.

Last month in Minnesota a collaborative report was issued by a diverse stakeholder group known as the e21 initiative. The group released a set of recommendations that are intended to act as a blueprint for a new customer-centric performance-based regulatory approach. Following the e21 report, we filed with the Minnesota commission, a framework on how we envision enabling these changes.

We focused on four key objectives. Lowering carbon emissions by 40% by 2030, pioneering distribution grid modernization, responding to changing customer preferences and providing new services and products, and, finally, pursuing more predictable and nimble rate recovery. In order to effectively bring about these changes, it is essential that the Company have a longer term, more holistic regulatory compact. Longer term multi-year agreements and additional riders are expected to improve visibility and supplement our efforts.

Further, the Company has tools it can utilize to stabilize rate increases and make bills more predictable for our customers. We expect to work with the commission and various stakeholders in Minnesota in 2015 to develop this new regulatory framework and have requested a planning meeting in the coming months to discuss potential options in greater detail. We are also exploring ways for us to avoid the need to file a 2016 rate case, which would allow more time to concentrate on the longer term regulatory framework.

In January, we filed our resource plan in Minnesota, which provides details on how we will achieve our commitment to reduce carbon emissions by 40% by 2030. This will be accomplished by significantly increasing the amount of solar and wind on the NSP system, adding natural gas generation, continuing our industry leading commitment to conservation programs, operating our nuclear plants at least through their current licenses, and continuing to run Sherco units 1 and 2 with gradual decreased reliance on those units through 2030. This proactive, no regrets strategy will better position the Company and our customers for the long run and do so at an incremental cumulative cost of less than 3% through 2030. As a result, by 2030, 63% of our energy will be carbon free at NSP.

Clearly, 2015 is going to be a transformational year in Minnesota. While much of our discussion is focused on Minnesota, we are also pursuing changes in our Texas jurisdiction. Along with other non-ERCOT utilities, we will be sponsoring legislation this session that will help reduce regulatory lag and allow us to continue to invest in the systems to support growth in the region, which is continuing even in the face of a challenging oil price environment.

Finally, we wanted to update you on our natural gas growth initiatives. As we mentioned last quarter, we plan to file a general rate case for our Colorado gas business. The filing will include a number of investments to maintain and improve the safety and reliability of our natural gas infrastructure. Concurrent with our rate case, we will begin working with our commission and major stakeholders to explore rate basing natural gas reserves as a way to take advantage of the current low natural gas price and to provide a longer term hedge for our customers.

Following our stakeholder and outreach in education, we expect to make a separate filing to begin the regulatory process. We are excited by the progress we have made and the steps we have taken thus far, and I look forward to updating you later this year. With that I will turn the call over to Teresa.

Thanks, Ben. And good morning.

Today I will be focusing my discussion on full year 2014 results. We are pleased to close out another solid year with ongoing earnings of $2.03 per share compared with 2013 ongoing earnings of $1.95 per share. The most significant driver related to 2014 earnings was improved electric and natural gas margins that benefited from new rates and increased rider revenues in many of our jurisdictions. Increased margins more than offset an unfavorable weather comparison and higher O&M depreciation and property taxes.

It is worth noting that the weather in 2014 contributed $0.03 per share when compared to normal. In contrast, in 2013 weather contributed $0.11 per share, resulting in a $0.08 per share decline when comparing the two years.

Now let me provide an update on sales and the economies in our local service territories. We experienced positive growth trends in 2014 with weather normalized retail electric sales increasing 1.3% and firm natural gas sales improving 4.6%. Sales in 2014 exceeded our original expectations for the year. While we are monitoring economic conditions in our service territories and are closely watching potential implications from changes in the E&P space, we remain confident in our 2015 electric weather adjusted sales growth assumption of 1%.

Let me provide a little more detail on sales growth by company. Beginning with NSP Wisconsin, weather adjusted retail sales increased 3.3% in 2014 due to strength in C&I sales, from growth in the sand mining industry and related oil and gas businesses. Customer growth and modest usage increases drove higher residential sales.

Electric sales at SPS increased 2.3% driven by growth in the C&I class. Oil and gas exploration in the Permian Basin continues to benefit the service territory and we saw additional growth in uranium enrichment. While we are watching oil price closely and expect some producers to reduce new drilling activity, we anticipate that others will continue to grow production.

PSCo sales increased 1.2%, which was primarily attributable to strength in the C&I class due to new food manufacturing customers and energy sector growth. Finally, NSP Minnesota sales increased 0.6% driven by growth in the number of residential and small C&I customers and usage increases in the small C&I class.

Economic conditions remain strong across Xcel Energy's service territories relative to the nation as a whole. The consolidated unemployment rate in our regions of 3.6% remains well below the national average of 5.4%. In addition, the number of jobs in our region's grew 2.3% during 2014 compared with 1.9% for the nation.

Focusing more specifically on 2014 earnings, ongoing electric margin increased $215 million. Key drivers included implementation of final and interim rates, which increased margin by $129 million; non-fuel riders increased margin by $57 million; increased transmission investment, which improved margin by $31 million; and retail sales growth, excluding weather, improved margins by $24 million.

These positive impacts were partially offset by an unfavorable weather comparison year over year of $60 million, as well as a few other items. The electric margin results reflect an estimated refund obligation for the Minnesota rate case, which is relatively consistent with the recent ALJ recommendation and an estimated customer refund liability to capture the impact of our electric earnings test at PSCo.

Margins on the natural gas side of the business increased by $49 million for the year. This is primarily due to rate relief in Colorado, significant infrastructure investment that is captured in an annual rider, and retail sales growth. O&M expenses increased $61 million, or 2.7% for 2014, solidly within our original guidance of a 2% to 3% increase. The increase is primarily driven by higher, although moderating, nuclear costs.

As we have discussed in the past, a key objective of our operational excellence strategic pillar is to limit O&M increases. We are reaffirming our 2015 O&M guidance of 0% to 2%, consistent with our long-term objective. In addition, I think it's worth mentioning that our 2015 O&M guidance assumption reflects a lower pension discount rate and adoption of the recently updated mortality tables. Finally, other taxes increased about $45 million, or 11%, largely driven by higher property taxes in Minnesota, Texas, and Colorado.

Next I'll update you on several regulatory proceedings. Additional details are included in our earnings release. In Colorado, we are pleased to have reached a settlement with Hardy's that will successfully resolve our electric rate case. The agreement continues the productive multi-year regulatory compact that we have been operating under since 2012. The settlement calls for a total increase of about $53 million, or 1.9%, based on an ROE of 9.83% and an equity ratio of 56%.

In addition, we anticipate the PSCo will defer about $3 million of expenses in 2015. The agreement also stipulates that both the clean air, clean jobs, and transmission riders are forward-looking mechanisms.

It is worth noting that in our original Colorado rate case we had proposed shortening the depreciable lives of certain assets which would have led to a material increase in depreciation expense. As a result of the settlement, PSCo will not be implementing the depreciation changes and will avoid this incremental depreciation expense. Alternatively, we agree to file a stand alone depreciation study early next year that will be incorporated into our next rate case anticipated in 2018. The commission is expected to rule on the settlement in the first quarter and rates are expected to become effective in mid February.

Last month we received the ALJ recommendation in our Minnesota electric case. We were encouraged that the judge acknowledged the strength of the Company's position on many of the key issues including pensions, benefits, and depreciation. When including the ALJ's recommended ROE of 9.77% and adjusting for sales and property tax true-ups, we estimate a cumulative revenue increase of about $192 million for 2014 and 2015. Deliberations are currently scheduled for March.

Turning to our Monticello prudence review. We have not yet received the ALJ recommendation. We believe the delay is related to workload issues for the ALJ and anticipate the ALJ recommendation in February. We continue to believe that we acted prudently in making decisions throughout the course of the project. In addition, the surrounding communities and our customers have largely rebuilt, safe, and efficient source of carbon-free low-cost power for many years to come.

Importantly, we don't believe that the delay in receiving the ALJ's recommendation will impact the current schedule and we continue to expect the commission to deliberate on the proceeding in March. In Texas, we filed a rate case requesting an increase in annual revenues of $65 million or 6.7%. Our filing reflects the inclusion of post test year rate base additions. One of the items we are seeking legislative support for in Texas. New rates are expected to be implemented by mid year.

In South Dakota, we put interim rates of about $16 million in place on January 1, and continue to work through the regulatory process. Final rates are expected to be approved mid-year.

We also made progress on several other initiatives during the fourth quarter. In Wisconsin, the commission approved the settlement agreement which we reached last year with staff and intervenors for a rate increase of $14 million or 2.2%. Rates went into effect earlier this month.

In Texas, the commission approved our settlement in the 2014 rate case providing incremental revenue of $37 million, or 3.5%. Rates went into effect retroactive to June 2014. Finally, in Minnesota the commission approved our gas infrastructure rider for $15 million with rates becoming effective in February 2015.

In summary, 2014 was a busy and productive year for us on the regulatory front. This morning we are reaffirming our 2015 earnings guidance of $2.00 to $2.15 per share. Our guidance range is based on several key assumption as described in our earnings release, including constructive outcomes in our regulatory proceedings. Please note that some of the assumptions have changed due primarily to incorporating actual 2014 results. With that I'll wrap up my comments.

After a solid 2014, we are pleased to deliver earnings within our guidance range for the tenth consecutive year. We are reaffirming our 2015 earnings guidance range of $2.00 to $2.15 per share. Our five-year capital plan of $14.5 billion and our 4.7% rate base CAGR, even when considering the impacts from the recently passed bonus depreciation legislation.

We continue to see improved economic conditions in our regions and experience better than expected sales growth with 2014 weather adjusted retail electric sales growth of 1.3% and weather adjusted firm natural gas sales growth of 4.6%. We are making meaningful progress on the regulatory front, including the recent multi-year settlement in Colorado and expect to reach a conclusion in the Minnesota case in the next few months.

We delivered 2014 O&M expense growth within our guidance of 2% to 3% and continue to expect 2015 O&M to be flat to 2%. And finally, we are well positioned to deliver an attractive long-term value to our shareholders by growing earnings and our dividend 4% to 6% annually. So with that, operator, we will now take questions.

Thank you very much.

(Operator Instructions).

We will take our first question today from Michael Weinstein, UBS.

Can you hear me?

Yes, we can hear you.

Okay. Great. Excellent. Perhaps first, if you can, you talked a lot about the future here. You talked about the IRP.

Can you perhaps comment on the ability for Xcel to take advantages of opportunities, perhaps in solar, in the near term and perhaps in the long term? And perhaps, also, at the same time elaborate -- you introduced a comment, other products and services. Perhaps, could you elaborate a little bit on what you meant there as well?

Sure. And we are going to add, obviously, as part of that, the Resource Plan, a tremendous amount of renewables, both wind and solar. A lot of it comes in the 2020 through 2030 timeframe. I think that gives us a great opportunity to own a good piece of those investment opportunities, for a couple of reasons.

One, clearly, technology will come down and it will most likely not have as much of the federal tax incentives that it does have now. Two, our tax appetite should grow in the coming years. So, I think we should be well positioned to take advantage of some of those opportunities. Your second question was regarding?

I suppose you have made this, curious, comment offering other products and services. I am just curious if that is anything tangible?

Yes. There's is a number of things that we want to do. Increasingly, customers want a different energy mix. They want greener products. They want different billing options.

It's basically just responding to the trend that we have seen, that consumers, one size fits all, which has been the traditional utility role needs to change, and we want to work with the commission and their staffs to make sure that we do that in a way that is fair to all and be flexible enough to move forward with that.

Excellent. And if you don't mind commenting on transmission here. I would be curious, where does your TransCo strategy stand, given some commentary from peers and the SPP market overall of perhaps a lackluster spend trajectory here at least for 2015?

How does that jive with what you are [baking] into expectations and your own expectations for longer term buildout of the TransCo? A perhaps a clarification on the last question. Does that mean for solar it's an opportunity for you all post the 2016 ITC? Is that what I'm hearing from you?

It means that the opportunity improves significantly. It doesn't mean we can't do something before that. But, as you know, renewables are heavily driven by tax appetites. You need one to efficiently -- it doesn't mean you are fully precluded, but to efficiently participate in the markets.

Your question was about TransCos and transmission. Keep in mind that $4.5 billion of our CapEx over the next five years is in transmission. None of it is in a TransCo and none of it assumes that we win any of the competitive transmission projects. When you looked at what has come out of SPP and their ITP-10 plan, I think it was about $300-odd million of potential opportunities. By the way, it looks like not an insignificant amount of that would go into SPS. But that would be the icing on the cake.

So our strategy has always been two-pronged. We have the utility vehicle to invest in. That's where we are today. We are in the process of getting approvals -- final approvals on our TransCos, so that we can participate in those competitive markets. I think we are well positioned to do that.

It's going a little bit slower, as you mentioned, than I think many people thought. That doesn't really surprise us. I think there will be more opportunities in the years to come and, again, I think we will be very well positioned to win in those markets.

But to summarize, you feel confident in the $4.5 billion you have already delineated in executing on that, despite, perhaps, a little bit of the lacklusterness in SPP, et cetera?

Those, by and large, are identified projects. Yes, we feel very confident in that.

Okay. Great. Thank you very much for the time.

Thank you.

Ali Agha with SunTrust is next.

Can you remind me, in your 2015 guidance range right now, what kind of regulatory lag is assumed there? And best case scenario, how much of that do you think you can ultimately capture?

Just historically, we have been running about 100 basis points in terms of regulatory lag. And, as we talked about, as one of our priorities is, we intend to close that gap at 50 basis points. That is our target.

Now, that's not evenly spread over the next years. But we do intend to start to put that in place in 2015. So we are working toward some improvement in that. It will -- the trajectory is, again, not ratable, but will move up. So it's smaller in the first years.

To be clear, you said the starting point in 2015 -- I think the [2 to 2015] guidance, that is still assuming at the mid-point about 100 basis point lag?

Yes. It's a little bit -- it's right around there. We've assumed just a slight piece.

Okay. Then my second question. As you mentioned, you ran -- weather-normalized electric sales were up 1.3% in 2014, ahead of, perhaps, your origin plan. But, I noticed that for 2015 you are still assuming 1% and, I think, for gas your actually assuming a 2% decline.

Right.

So why the slowdown in electric? What are you seeing in 2015 that causes you to be more cautious?

We are just being conservative in terms of our overall outlook in terms of 2015. As we've talked to you -- and this goes for gas, too, in previous quarters. Early in the year we had some extreme weather and we were always concerned.

We had a little bit of weather wrapped up in our overall sales, both in the electric and gas business. So we are just being conservative, Ali, in saying that. It's not any significant item that's driving us to keep it at that level, the 1%.

Okay. And then, I wanted to be clear. You know, the comments you made that, in your next Colorado Gas Case, you do plan to also ask to put some of your gas reserves into rate base. Can you remind us if that happens, what kind of incremental rate base does that mean? Also, what is the mechanism? I wasn't unclear. Is it part of the rate case? Is it a separate filing? Just want to be clear on how this goes.

I don't know if we are actually going to talk very much about it in the actual case that we'll file to get recovery of core infrastructure investments, Ali. What I said is that we would do a concurrent filing. A separate filing that will take place most likely in the second half of this year. We are going to gather stakeholder input. Understand what the important issues with our stakeholders are.

Assuming those conversations and the filing goes well and, I assume they will be open-type meetings, then look for us to pursue a defined and more fleshed-out plan, obviously, in the 2016 timeframe. We purchase about 450 Bcf a year. So what is that? At $3.00, that's about $1.2 billion of gas. Obviously, we wouldn't do it all. You would lay into it slowly. I think with the emphasis more on our LDC gas business in Colorado.

Okay, but just the mechanism. I mean, if it moves into rate base, you would want rate increases to reflect that. So would that be put in as part of this rate case filing? Would that be a separate rate case? How would the rates be adjusted if it you do get it into rate base?

It would be separate. The whole premise is, it's fuel for rate base. And so, how that mechanism would be determined, there is different models out there, as I think you're aware, and we would -- that's the kind of input we want from stakeholders, to understand what risk they are willing to bear and which risks they are not willing to bear, and then we can move forward accordingly.

Okay. Final question. In the past, Ben, you have also talked about looking at opportunities where you have current BPAs and that may be expiring. Is there an opportunity to rate base some of those plants? As we look at calendar 2015, just looking at where you are in terms of contracts, et cetera, are there opportunities that could play out this year, or is this something that we should think about beyond 2015?

I think there is always opportunities. And we're always looking for those opportunities, to your point. And so, I can't promise anything. We certainly are diligently looking at those opportunities.

It could happen this year if something comes together?

It could.

Thank you.

Thanks.

Our next question comes from Greg Gordon, Evercore ISI.

Hey, Greg.

Thanks. Good morning, guys. Ladies and gentlemen. First question is on the Colorado rate case. How much of a depreciation increase had you initially asked for that was subsequently removed in the context of the settlement?

Greg, it was north of $30 million.

Okay. Thank you very much. Second question is on cap spending. And I'm referring to the slides you brought to my conference a couple weeks ago. They were pretty consistent, I think, with prior disclosures.

You have a $3.375 billion spend in 2015, declines to more or less $2.8 billion in 2016, 2017, then dips a little bit in 2018, comes back up in 2019. So that averages $4.7 billion, but it's front-end loaded. And then you have made these subsequent filings in Minnesota. Specifically on resource planning. So, is the bias to potentially see if you get by in Minnesota, to see that 2017, 2018, 2019 spend potentially go up?

Maybe I will just start there in terms of the spend, why we have that peak. Just as a reminder, Greg, it's the wind in Minnesota. The two wind farms that will go in service. So that is really the peak up. And then in terms of, relative to going forward, that once rates would change, assuming they do, we should level off in terms of our relative increases. But we do have the initial peak.

Right. I guess I'm asking -- I know you have a rate plan to smooth in those increases. My question goes more towards the overall level of cap spending, which declines as you get out into 2017, 2018, 2019.

Typically, Greg, and obviously no guarantee, but as you know, as we get into those out years, the actual spend has historically tended to increase as we identify new opportunities or new needs within our spending parameters. And I think we'll -- I think you also were asking about the resource plan itself that we filed. As I said, I think that could create some opportunities for us, albeit most of them would be in the latter part of that five-year forecast or even outside of that five-year forecast.

Got you. So when we think about your 5% to 7% growth aspiration, this plan drives slightly less in terms of rate-based growth. And then, improving regulatory lag to inside the range. But should you, in fact, identify more cap spending, than that whole sort of calculus moves up a bit.

Yes. We have tempered back the 5% to 7% to be closer to around 5% rate base growth, as we go forward. So it's a little bit lower than the 5% to 7% as we in past years have talked about.

We always look for rate-based opportunities, Greg, to your point. Also to your point, the thing that will really drive earnings is closing that ROE gap, as Teresa mentioned. I think we are making good progress on that. We are excited about continuing what has been a good deal for customers and shareholders in Colorado. And I am encouraged with the progress we are making here in Minnesota.

Great. And then a final question is, last year you raised the dividend first quarter, whereas in prior years you had raised it later in the year. What is your expectation of the current dividend cycle to this year and going forward?

Well, we addressed that with the Board. So you probably can assume that last year's cycle will be more consistent going forward.

Okay. Thanks. Take care, guys.

Our next question will come from Travis Miller with Morningstar.

Good morning. Thank you.

Hi, Travis.

Hi, Travis.

Hi. I wonder if you could talk a little bit about the impact on you guys from the oil price drop and how that might be incorporated, or not, in that 1% demand forecast. Anything around that that would have a material impact?

Let me start and I will let Teresa add if she thinks I've missed anything. One, as Teresa mentioned, 1% is probably all things equal, a fairly conservative sales forecast. So we have margin, reserve margin, if you will. But actually, we don't really see much in the way of -- we do sales coming out of the decline in oil prices.

And to the extent we do, keep in mind that that is probably the lowest margin part of our business. So, I don't think it's a big impact, Travis. I really don't. And we don't think it's going to be a big impact on our capital spending profile either.

Okay. Great. And one on the Colorado case, on the electric side. How much, given the adjustments you were able to get out of the Clean Air-Clean Jobs and the transmission into riders, and such, how much, now, can you give a sense on a percentage basis or idea, is subject to demand? Demand sensitive, in terms of earning ROE.

In terms of just the sales growth?

Yes. Needing sales growth to compensate for the net-capital investment that you guys would see over this three-year period.

I think it's very moderate in terms of that, because those were our biggest drivers in terms of that cost recovery and having those mechanisms in place. We are definitely predicting sales growth, but it's not dependent in terms of earning our ROE on having an aggressive sales growth achievement.

Yes. I would agree with that, what Teresa said. Of course, the riders help with the incremental, but you have your core business. So sales growth is always an issue. But I think we have that reasonably pegged. To Teresa's point, we are not assuming an aggressive sales forecast in those numbers.

Okay. Great. Thanks so much.

Next is Chris Turnure, JPMorgan.

Good morning, guys. I wanted to follow up on the e21 Initiative. You mentioned that you came out with the initial blueprint back in December and then you actually filed with the MPUC this month for a specific rider mechanism of some kind. You were a little bit high level with the description there.

I wanted to find out a little bit more in the way of detail and find out more in the way of timing. And then, also, I wanted to understand the interplay between that request and then the fact that you bundled in some futuristic carbon goals as well. How do those two relate within that request?

To try to answer that, it's all about having a longer-term approach to what we're trying to accomplish in Minnesota. So the Resource Plan, we went out further. Here's what we can do by 2030. Here is how we get there. Let's focus on the key objective, which is carbon reduction. Let's be very disciplined about how we achieve that carbon reduction using what we like to call technologies at the speed of value.

So, disciplined on how we approach it. And let's make sure that our regulatory compact reflects that longer-term view. So, yes, we outline general frameworks. But generally, what we're looking for is longer term regulatory compacts. We like to see compacts three, four, maybe even up to five years long. And within that, you can augment that with riders. You can use formulaic recovery type mechanisms, and then have the incentives for achieving what I think the state wants us to achieve.

So, we left it deliberately vague, but we are building off that e21 Initiative, which we participated in but we didn't drive. So I really think there is an excitement here in Minnesota as we have outlined these plans and talked about how we can achieve these carbon reduction goals at a very, very modest price to consumers. More to come on that. But I think it's a pretty exciting time.

Maybe just to add to that. And just to clarify, Ben outlined the framework. But I think you mentioned that we had made a rider request. We haven't specifically done that. Just to add to Ben's comment in terms of the overall framework.

Okay. Got you. So nothing specific with a rider request. And then just stepping back, overall this is more driven by future growth, future spending demands and initiatives, and then those are going to potentially necessitate some kind of rider or catch-up mechanism to compensate you for that?

Well, there is different ways you can get there. So, the point is that we're moving to a different environment and we are going to need the regulatory compact to evolve with it. The key takeaway, I'd hope you would get, is what we're really seeking is a more comprehensive multi-year approach.

Okay. And then, do you guys have any color around initial conversations there with regulators and then, separately, in either Minnesota or in Texas, initial conversations with policy makers and the timing around your legislative initiatives in both of those states?

Yes. Well, let me just say that I have had the opportunity, as have others on the Xcel team, to talk about what we're trying to accomplish. As I mentioned, I think there is a lot of excitement and I think there is -- the devil is always in the details, as you know. But I think there is a lot of excitement that this is the way we ought to be going as a state. So that's from a regulatory perspective. We would like to potentially have legislation that would support that new regulatory framework in Minnesota. More to come on that, obviously.

In Texas, I think we are getting some traction. It's still a little bit early days. They haven't even assigned -- made committee assignments to the key committees that would drive legislation for us. But, we haven't seen any major roadblocks at this point.

Great. Thanks, guys.

Thank you.

At this time a question from Jonathan Arnold, Deutsche Bank.

Good morning, guys.

Hi, Jonathan.

Quick one. You mentioned exploring ways to avoid a 2016 Minnesota rate case. Could you elaborate?

Yes, let me take a stab at it. First of all, where there is a will, there is a way. As I've said, I think there is really a will to -- let's get the 2016 case out of the way and let's focus on this longer-term framework. So how would we do that mechanically? It starts with using the ALJ recommendations.

Getting our interim rate proposal adopted close to what we proposed. And then, taking a look at our excess depreciation and, maybe, reshaping that a bit, along with using some of our nuclear depreciation as well. So there is a way, Jonathan. And it would be nice to free up the time so we could spend more time on these other more longer-term ideas that the community and we have.

It sounds like you might be reasonably well along with having getting that done? Is that fair, Ben?

I think the first step in getting it done was a constructive ALJ settlement. So we have something to work with now. Again, if the parties want to do it, I think we have the pathway forward.

Okay. And then another topic. The gas rate basing subject. Given the change in the commodity price, obviously, it would seem interesting for some of your stakeholders to lock that in. How confident are you that you will be able to find the other side of the deal?

There is definitely an economic benefit to moving forward. Especially where gas prices are today. But we have to make sure that -- there will be a lot of concerns. I mean, these aren't -- this won't be an easy lift. But I think the economics are compelling enough that I have optimism that ultimately we can get something done. But it's going to take time, Jon.

My question was a bit more to, do you see appetite from producers to lock in these prices?

Oh, well, yes. I think you can find the producers. That's not going to be an issue.

You're more focused on your side?

Yes.

All right. Thank you very much.

Right. Thank you.

(Operator Instructions) Next we will hear from Ashar Khan, Visium Asset Management.

Good morning and congratulations on great results. Teresa, you mentioned the bonus depreciation. What is the cash flow impact?

The bonus depreciation, for basically the extension?

Yes.

It's a combination. It's about $1.8 billion. It splits between the two years, about $1.4 billion in 2014 and about $400 million in 2015, because we have some carryover.

So that's the extra cash you will get?

Well, that's the bonus depreciation amount. So it's a tax impact on that.

So I can take that number and do a tax impact on that?

Yes.

Okay. Okay. And so, is that now factored in into your -- I guess how does that help? Does that lower debt needs or how is that cash being used in the process?

Well, we have factored into our overall guidance in terms of the effects of the bonus depreciation. So, we have taken that all into account. To the extent we have that, we also have some rate-based offsets. So it's a combination. We factored that all into our 2015 guidance in our update.

Okay.

One thing you'll notice, Ashar, is that we have reduced our planned-debt issuance over the five-year time period. The other thing is, obviously, some of this bonus depreciation comes in NOL and it's pushed forward, because you can only utilize so much of it per year. It's had a modest improvement in our cash flow needs, or our financing needs.

Okay. Okay. Okay. Thank you.

Thank you.

Thanks.

And that does conclude our question-and-answer session. At this time I will turn the conference over to Teresa Madden for any closing or additional remarks.

Thank you all for participating in our earnings call this morning. Please contact Paul Johnson and the IR team with any follow-up questions. Thanks again.

Thank you, everyone.

And that does conclude today's conference call. Thank you for your participation.