Benjamin G.S. Fowke III – Chairman of the Board, President, Chief Executive Officer Teresa S.

Madden – Chief Financial Officer, Senior Vice President Scott M. Wilensky – Senior Vice President, General Counsel David M.

Sparby – Senior Vice President; Group President of Xcel Energy Services Inc. George E.

Tyson II – Vice President, Treasurer

Travis Miller – Morningstar Ali Agha – SunTrust Robinson Humphrey Anthony Crudel – Jefferies Dan Jenkins – State of Wisconsin Investment Board Timothy Yee – KeyBanc Capital Markets

Thank you, and welcome to Xcel Energy’s First Quarter 2012 earnings release conference call. With me today are Ben Fowke, Chairman, President and Chief Executive Officer; Teresa Madden, Senior Vice President and Chief Financial Officer; Dave Sparby, Senior Vice President and Group President; Scott Wilensky, Senior Vice President and General Counsel; and George Tyson, Vice President and Treasurer.

This morning we’ll provide you with an update on recent business development, discuss first quarter results, review our 2012 earnings guidance, highlight our strong corporate governance and take your questions. As a reminder, there are slides that accompany today’s call which are available on our web page.

In addition some of the comments we make will contain forward-looking information. Significant factors that could cause results differ from those anticipated are described in our earnings release and our filings with the SEC.

I’ll now turn the call over to Ben Fowke.

Thank you, and good morning. Today we’ve reported first quarter earnings of $0.38 per share compared with $0.42 per share in 2011.

I’m sure you’re aware that weather was significantly warmer this quarter, and that had an adverse impact on our results. However, we’ve initiated actions to help offset the impact of warmer weather and lower than forecasted at electric sale.

As a result of our efforts, quarterly O&M expenses came in roughly flat with last year. Looking ahead, we continue to expect 2012 earnings to be in the lower half of our earnings guidance range of $1.75 to $1.85 per share.

Now Teresa will discuss our quarterly results and earnings guidance in greater detail in a few moments. I’ll now provide you with few updates, beginning with the review of our regulatory development.

In Minnesota, we are pleased that the Commission approved our rate case settlement at the end of March. The annual rate increases of $58 million in 2011; $15 million in 2012 are based on 10.37 ROE.

This settlement also includes a $30 million reduction through depreciation expense. As part of the settlement in the Minnesota Electric case, the settling parties recognized that NSP Minnesota would follow up the decision sticking deferred accounting for 2012 property tax expense above the level approved in a rate case.

In December, we filed the petition requesting a deferral of incremental 2012 property taxes, which are currently estimated at $24 million. In April, the Department of Commerce recommended that the commission denied the request.

However, a coalition of large industrial customers and the Chamber Of Commerce were supportive of our deferred accounting request. Our earnings guidance reflects the assumption that we are able to defer incremental property taxes in Minnesota.

We believe we’ve met their criteria for deferred accounting treatment. Last week, we filed our response to the department’s concern, which provide strong support for our request.

We expect the Minnesota PUC to rule on this request during the second quarter. In Colorado, we arrived at a comprehensive multi-year rate settlement agreement with the PUC staff, the office of consumer counsel and several other intervenors.

The agreement reflects a 73 million electric rate increase in 2012; an incremental $16 million increase in 2013; and a $25 million increase in 2014, based on a 10% ROE and a 56% equity ratio. In addition, the settlement enables us to defer incremental property taxes.

We believe this is a constructive settlement that provides revenue and regulatory certainty for both our customers and our shareholders, while establishing a regulatory framework for a multi-year plan. Hearings were held on Tuesday, and the commission is deliberating on the settlement this morning, and may rule later today.

Turning our focus to 2013; in June we plan to file an electric and natural gas case in Wisconsin. During the second half of the year, we plan to file several cases, including electric cases in Texas, New Mexico and North Dakota.

Finally, we plan to file an electric case in Minnesota, where we are anticipating pursuing a multi-year plan. Together these cases will drive earnings in 2013.

One final regulatory item. In March, we asked the Minnesota Commission to reaffirm that increasing generating capacity at our Prairie Island nuclear plant within our customer’s best interest.

We are seeking a reaffirmation as much as change since the Commission issued a certificate of need for the Prairie Island operate in 2009. Key changes since 2009 include a more lengthy approval process at the Nuclear Regulatory Commission, less expected incremental output from the plant to operate, higher project costs, lower natural gas prices, as well as lower demand growth.

When circumstances change significantly after an initial regulatory approval as with this project, our approach is to step back and take another look before continuing. It’s prudent to have this review now rather than after completing the project.

This is consistent with our focus on stake holder alignment. We anticipate the Minnesota PUC will rule on this request later this year or early next.

We also continue to make good progress implementing our transmission strategy. Notably, the Minnesota Commission granted the last siting and routing permit needed for the CapX2020 lines in Minnesota.

The right of first refusal bill was signed into law in Minnesota. We began phase II of the Fargo-St.

Cloud line and the construction of the Brookings Hampton line and in Texas we reached a settlement for the route of the Tuco-Woodward line. Clearly, our transmission projects remain on track.

Next, I’d like to provide you a brief environmental update. During the last year, EPA continue to pursue its regulatory agenda, which significantly raises the bar for environmental compliance.

In most cases, our proactive environmental strategy has dramatically reduced our cost of compliance with EPA’s new mandate. For example, in late 2011, EPA finalized its Mercury and Air Toxics Standards rule.

But we’ll have to make some emission control investments under this rule; our cost of compliant is lower than the rest of the industry, primarily because of the actions we implemented over the last decade. EPA also proposed to approve, our regional haze plan for Colorado this year.

That plan incorporates our Clean Air Clean Jobs emission reduction program, a plan which mitigates the cost of EPA regulations for our customers. As a result of our proactive environmental action, Xcel Energy is well positioned to meet various environmental challenges over the next decade.

We believe our customers and shareholders had benefited from these actions. The biggest environmental challenge we’re currently facing is EPA’s CSAPR rule.

Because of its short compliance window, CSAPR was unusual and that it had a significant impact on Xcel Energy and our customer. As a result, we joined other utilities in several states in challenging the rule and seeking its stay.

Late last year, the Court of Appeal stayed the rule, while it continue to consider the merits of our challenge. Last month the court listened to arguments over the legality of the rule.

We expect the ruling sometime this summer and remain optimistic that this litigation will result in better environmental regulation. Clearly, public policy will continue to impact our capital spend.

Our five-year capital forecast includes approximately $470 million for CSAPR compliance; and $300 million for the Prairie Island upgrade. The changes in timing or compliance with CSAPR as well as the Minnesota Commission’s decision on the upgrade to Prairie Island could potentially reduce our capital forecast.

If these projects are modified or canceled, we still project strong rate-based growth over the next five years. In addition, a reduction in our capital forecast would reduce our financing requirement, and provide us with increased flexibility.

One final comment before I turn the call over to Teresa. The continued low price of natural gas is a hot topic for our industry.

With deal closes or recovery mechanisms in all of our states, low natural gas prices are very beneficial for our customer and for Xcel Energy. This is especially true as we investments to modernize our systems.

Our customers see lower bills, and a lower share of their income is spent on energy consumption. While we make investments in our system to provide our customers with long term value, our mission is to provide our customer with clean, safe, reliable energy at a competitive price.

Lower fuel prices certainly help us achieve that mission. Tune it over to Teresa.

Thanks, Ben, and good morning. Today I will discuss first quarter results, 2012 earnings guidance and a shareholder proposal included in this year’s proxy.

Let’s begin by reviewing our first quarter results at each of our four operating companies. As Ben indicated, warm weather throughout our service territory negatively impacted our first quarter results, mostly notably in Minnesota, which experienced the warmest March in over 100 year.

For the quarter, earnings at PSCo decreased by $0.01 per share due to lower sales as result of the warmer weather, decreased wholesale revenue due to the expiration of the Black Hills contract, higher depreciation and interest expense partially offset by higher gas revenues, resulting from new rates that were effective in September 2011. At NSP Minnesota, earnings decreased by $0.03 per share due to weather, final rates which were lower than interim rates last year, higher property taxes and higher O&M expenses.

These negative drivers were partially offset by a lower effective tax rate, which I’ll discuss in a few moments. Earnings at NSP-Wisconsin and SPS were both flat for the quarter.

Quarterly results at both companies were positively impacted by new rates effective in January 2012, offset primarily by the negative impact of weather. Let’s take a closer look at the drivers that affected various line items in the income statement beginning with retail electric margin.

Our first quarter electric margin decreased by $25 million, primary drivers of the reduced margins were $22 million from the estimated impact of weather and $11 million from lower firm wholesale revenue largely driven by the expiration of the Black Hills contract. These negative items were partially offset by higher transmission revenue, retail rate increases in several states and other smaller items.

Weather normalized retail electric sales grew 0.3%, and had a negligible impact on electric margin. However, this modest increase included the benefit of an extra day of sales due to leap year, without the extra day the first quarter electric sales declined eight tenths of 1%.

We might recall that our fourth quarter sales were also slightly negative. This is a disappointing trend, and as a result, we now expect our weather adjusted annual sales growth to be flat for 2010.

Natural gas margins decreased by $19 million in the first quarter, primarily due to warm winter weather which reduced margins by $21 million. Turning to expenses, first quarter O&M expenses were essentially flat for the quarter.

In January, we began a comprehensive review of our O&M expenses with a goal of not compromising reliability or customer service. We were able to implement several initiatives such as deferring merit increases for non-bargaining employees, reducing incentive company accrual, corresponding new hires, cutting training and other items to offset the impact of lower than forecasted sales and warm weather.

As a result of these actions, we now expect O&M expenses to increase between 0% and 1% for the year. Previously, our guidance reflected an annual O&M increase of 3% to 4%.

Other taxes increased approximately $9.1 million or 9.4% largely due to increased property taxes in Minnesota. As Ben discussed, we’ve requested deferral of incremental property taxes in Minnesota for 2012.

However, we’ll continue to expense the incremental property taxes until the Minnesota Commission rules on this issue. If our request is approved, we would retroactively defer these incremental property taxes for the beginning of the year.

You may have noticed, we have an effective tax rate of 29% for the quarter. We expect this tax rate was primarily due to the recent completion of a tax planning analysis regarding the eligibility of certain expenses that qualify for an extended carry back.

As a result of the differential between a higher tax rate in prior years and the current tax rate, we recorded a tax benefit of approximately $15 million in the first quarter. As a result of this tax benefit, we’ve adjusted our projected effective tax rate for 2012 to a range of 34% to 35%.

This has been a challenging year for us, very warm winter weather and declining normalized sale. However, we’ve taken steps to at least partially offset these impacts by managing O&M expenses and implementing a tax planning strategy.

Clearly, we still have a lot of work to do. With our management action, normal weather the rest of the year and assumed constructed outcomes in our regulatory proceedings, including commission approval of our settlement agreement in Colorado, and our deferred property tax request in Minnesota, we continue to expect to deliver earnings in the lower half our guidance range, of $1.75 to $1.85 per share.

Before we open up the call for your questions, I’d like to draw your attention briefly to this year’s proxy statement, which includes the shareholder proposal for Xcel Energy to adopt the policy or the Chairman of the company would be an Independent Director. Our Board of Directors recommend a vote against this proposal.

Xcel Energy has demonstrated sound corporate governance trends for many years, including annual election of Directors, and independent non-employee Directors among its 11 members, an annual election of a lead Independent Director. Board committee is composed entirely of Independent Directors and Committee Chairs review and approve agendas for Committee meeting.

These practices have served our shareholders well. Xcel Energy has consistently delivered on its operational and financial objectives.

A strong track record is reflected and [achievement] of total return to shareholders that exceeded our peer group of the EEI investor owned electric and the S&P 500 Index for the 5 year period ending December 2011. The board believes that it is in the best position to evaluate the current and future needs of the company and to judge how the capabilities of the company’s Directors and Executives can collectively be most effective in meeting those needs.

The Board believes that maintaining flexibility to decide the appropriate leadership structure of the Board is consistent with effective governance by serving the shareholders’ interest and that this proposal would deprive the Board and its ability to govern the company in the manner it seems most effective. We request that you consider these factors as you vote your proxy in the coming weeks.

For more details, I urge you to review the Board’s response to this shareholder proposal in our proxy statement. If you have any questions or comments regarding the content of this year’s proxy, please contact our IR team.

That concludes my prepared remarks, operator we will now take questions.

Thanks, good morning.

Hey, Travis.

Good morning.

I wanted to go to Minnesota here for a little bit. If you get that property tax deferral there, do you think you can earn the allowed return of 10.37 in 2012, and corollary there, is that embedded in your guidance weather normalized?

The deferral of the property tax is embedded in our guidance, and the reality is, Travis, even with that deferral, the accounting order for the deferral of property taxes, we want to earn the allowed return of 10.37, I think we anticipate NSP Minnesota would probably be in the low 9.

What’s the biggest thing driving that, is the capital side or the operating cost side?

Well, I mean it’s this erosion of sales that we’ve seen in Minnesota which is probably the most pronounced in all of our jurisdiction. This is really the – essentially the second year of staying out or a rate case, and so there is a number of factors like that, that will push that down.

Ben, I’d just add to that, greatest impact of our weather is in the Minnesota company. So…

And then third on that, what risks you see if you file in November. Do you expect based on the negotiations from the previous year, though the risk I’m thinking of in ROE come potentially from even 10.37, disallowance of some kind of operating costs, disallowance of potential capital costs, what are the key risks based on settlement negotiations et cetera from previous case that could go into the November ’12 base?

I mean, I think the issues that you raised were always the issues when you ever could follow rate case. I mean, so I would probably say that the ROE would always have to – and it’s one of the key things we defend.

Our capital, Travis, tends to be a much easier sell, particularly because it’s pretty easy to see the value of that return. I mean this is a year, again, I want to talk about on the call, but we’re starting the year off very strongly with reliability and all the operating indicators that are so important to our customers.

And it’s really a reflection of the money we can put in into our system. So at the end of the day, I mean, it’s litigated, it’s as interveners, let’s see it another way, but I think at the end of the day, we’ve got a track record that demonstrates that, we get constructive outcomes.

And I think one of the advantage of going to a multi-year plan, like we did in Colorado, is we get that regulatory certainty, and we get a little pause. I mean, I think we have recognized that when you modernize an infrastructure, you follow a lot of rate cases.

So, I think it'd be nice to get a multiyear plan or something close to it and kind of get our marching orders and move on with it.

Okay, great. Thank you so much.

Thank you. Good morning.

Hi, Ali.

Hi, how are you?

Good morning, Ali.

Good morning, Teresa. Ben, if you look at Colorado, and assuming you do get the settlement approved, at least in Colorado should we assume that that gives you the tools to earn your authorized returns or are there still going to be lag there as well?

Well, Ali, there will still will be some lag. I mean, but I think we will close it a bit and I think we have a little more control of our destiny.

And, I mean, Ali we didn't get everything we wanted and then, that's kind of the way it goes when you do a settled agreement, but I think we made a lot of progress, we set the precedent going forward for multi-year plans. And I think if we manage expenses and capital in our business well that we can help eliminate some of that lag that plagued us in Colorado, but we won't cut it out completely by any stretch.

Okay. And, I mean, along those lines if you look at your two biggest jurisdictions Minnesota and Colorado, you are looking at multi-year plans, you get into run rate increases you got that in Minnesota as well.

From a logistic point of view, is that a particular functional change that is still required in both of those jurisdictions to be able to earn an authorized ROE, what needs to – in broad terms, what big item needs to change for you to eliminate the lags in Minnesota and Colorado?

Well, I mean, it will help us to bounce back. I mean, that would be one thing that helps in between rate cases.

Ali, it’s some of the expenses that we've had, the pension amortization which hopefully starts to level-off, I think in 2013 and beyond that will help and I mean as we start to – as our capital forecast starts to flatten-out, albeit at a relatively higher amount than we have seen historically, I think that will be helpful too. I don't know, Teresa, if you want to add anything?

I think you have covered the major items.

Okay. And last question, looking more near-term…

Ali, can I just…

Yes never mind.

Never obviously add something, but I will take it back. Go ahead.

Okay, I just want to say, near-term, when you look at the trends that you reported in the first quarter, including the tax benefit, was that sort of plugged in to your budget for the year? In other words, was Q1 pretty much on track, because if you took the tax benefit out, that’s about $0.03 swing right there?

So just wondering, was that a positive offset to some other slowdown or how should we be thinking about that in the context of your own budget?

I guess, let me start it out and I’ll have Teresa add. I mean the plan here – we knew we are planning around this tax benefit.

The question was going to be what quarter we would take it in and which is why we don’t do quarterly guidance. So, it was always in our guidance range of $1.75 to $1.85 and we knew we had that when we talked about it.

So, as far as the timing of it, I think that’s a function of when the planning was completed and some things like that. Teresa, I don’t know if you want to add anything.

I mean, you’re exactly right, Ben. I mean we had assumed a certain level in terms of the tax planning strategy.

We actually completed the work at the end of the first quarter. Obviously, we consulted with our auditors about different methodology, the approach, and the amount, and including the timing, and in fact, we determined it was most appropriate to recognize it in the first quarter.

So, again, short answer is, yes, we had assumed a level in our guidance, and in the quarterly estimates, there was some variability in that.

But earlier today you called out that you’re budgeting a 34% to 35% effective tax rate for the year. Remind me was that not the original plan or is it down from what your original plan was for the tax rate for the year?

It's down, it was 34% to 36% originally and which is now at 34% to 35%.

Keep in mind, Ali we expected that this would possibly come in, but weren't necessarily sure on the timing and the ultimate magnitude of it.

Got it, got it, thank you.

Hey, good morning. Some questions mainly related to Minnesota and I guess the regulatory environment.

You guys plan to file, I guess latter this year, rate case and when you see how sales and also weather had impacted you guys. Is there a potential for I don't know even if it's allowed for like revenue decoupling or something like that in Minnesota?

And the second question is, what type of premium does the regulators in Minnesota historically have given for a multiyear rate plan?

I don't think there's ever been a multiyear rate plan in Minnesota. So, this would be groundbreaking.

And, what was the first part of your question, I'm sorry?

First question was, is there any ability to get some revenue decoupling or somehow you guys you’re so impacted by either weather or just flat sales if there is some way that you could be made hold for a stuff like that?

I mean that’s always something – that’s a conversation that potentially we could have, but there's a lot of trade-offs with that and then there's a lot of devil in the details with those sorts of things. So I think we need to continue to evaluate that.

There’s others ways that I think accomplish something close to that – that maybe aren’t as dramatic. But we’ll keep looking at all the adoption.

And Anthony just a point to well we haven't implemented a multiyear rate plan in Minnesota. We have done step increases which is eventually a two-year rate increase.

We've done that both in Minnesota, North Dakota and Texas in the last year so that progress towards that multiyear plan.

It just seems that with flat sales or declining sales, and I know you're getting your step-up increases, but it's tough to have a stay-out of longer than a year, maybe two, just because there's really no incentive where I think you have to say a premium return or some type of premium, like a 50 basis point premium, maybe this as an incentive to book something longer than a year, but to put these sales, it just seems that you're going to always going to earn. Is that a right rate of this situation or no?

It depends how big the step increases are and what sales forecast is embedded on that and what kind of exit you have. We do have for example in Colorado, some exit ramps, albeit they are not without their pain, but that's the benefit I think, that's the trade-off and along with that goes with the benefits for multiyear plan.

So hopefully, you get your three year plan right, and you've got some true-up mechanisms and other things that such things are maybe outside of your control.

Maybe just to add to that in terms of the Minnesota sales, the compression we’ve seen has really to spend in the last two quarters and its two quarter the trend potentially, but we’re continuing to watch that. So it’s maybe a little bit early for that larger bit.

As Ben said, that's why we're looking at alternatives.

Great. Thank you.

Hi, good morning.

Hi, Dan.

I have some questions related around the regulatory issues and rate cases as well. First on Minnesota, you mentioned part of the impact in the first quarter was due to the approved rates being lower than the interim rates a year ago.

And I was wondering, how do you, I guess flow through that over recovery will that be over 12 months or how is that done just mechanically. How should we expect that to impact the year-over-year in comparison?

Well, when we were collecting early on the interim rate, we set up the revenue subject to refund and in essence those are – we've had all the true-up relative to the income statement, so they are not being given back to the customers. So we will not see any more income statement impact from that revenue subject to refund.

It's really, Dan, just the timing of the quarter, first quarter this year to first quarter last year because in first quarter 2011 we were recording at the higher interim rate level, subsequent to that that Teresa mentioned we made adjustments to recognize that.

And really why we were recording, we were recording at the ROE of 10.88 and the big driver down was 10.37. So…

Okay. I noticed that you also had similar outcome in North Dakota will that have any impact?

No.

Okay. And then I just want to verify.

I think you said that you expect later this year you are going file electric cases to just say Texas, New Mexico, and Minnesota were those the ones you said?

Correct.

Yeah.

What about the gas case in Minnesota, what was your ROE there, especially given the weak weather related sales and what's your plan for gas rates in Minnesota?

Dan, are you talking about our regulated 2011 return for our gas utility?

Right.

We don't file that until next week with the regulators.

Okay. You didn't mention anything about gas do you have plans at all that you might be filing?

We'll evaluate our gas business. I mean keep in mind, Dan, if you have warm, mild winter weather, it doesn't impact your revenue requirements when you file a rate case, because it's normalized.

So, you're absolutely right that our gas operations will be under-earning more than we anticipated because of the weather, but there's a number of other factors we have to consider before we file a rate case.

Okay. And then I was a little curious in your write-up about the rate case in South Dakota.

You mentioned the staff actually lowered the cost of debt, which is usually an embedded cost. What there a new issue or something that wasn't incorporated that they included that would cause them to lower the cost of debt?

Dan, I think you stumped the team. I suspect it has to do with capitalization of short-term and long-term and some other capital ratios, but we’ll probably have to take that offline and get back to you.

Okay, and then I was curious, once you take out the effect of the leap day, the commercial and industrial sales were down almost a percent, weather normalized, I was just wondering if you can give a little more color on what you are seeing since those sales typically aren’t as impacted by weather and what’s going on with your business customers?

In terms of – I would say for our large industrial customers in Minnesota and one of our large industrial customers is a paper mill and they’ve discounted a line of paper, they closed the board facility. So you are right, they are no impacted by weather, then we’re just seeing some in their business, business plans changed.

In Colorado our big customers are pretty much dismoderating, as they have been. We are not seeing big increases, but we are not seeing decreases either.

The biggest decreases are in this small C&I and the residential and that's really across almost all of our jurisdictions, it's most grounds here in Minnesota. It is a bit perplexing Dan because I mean if you look at the unemployment rates, job growth, et cetera we typically in all of our jurisdictions but we typically do a bit better than the national average.

So, I mean, it could be a number of factors that we're trying to analyze that are causing this trend. One of which might be more shadow effect of our own demand and conservation programs which we know probably take-off about 0.008% of sales and we're compensated for that, but maybe there's more of an impact than we realized.

I think the economy continues to impact customer behavior and then we're also looking at things like we're starting to see appliances get refreshed and maybe seeing some efficiencies there that perhaps we don't have our full handle on. So there’s a lot of things that we're looking at right now.

Okay. Then the last one I had was just related to, you mentioned that PS Colorado, the impact from loosing the, or expiration of that wholesale contract Black Hills.

Is that going to be continuing year-over-year negative for the rest of this year, when did that contract expire?

That contract expired at the end of the year, but we needed to shift from a cost recovery from wholesale to retail customers and that is incorporating in our Colorado settlement. So assuming we get new rates, the 1st of March and that will cover that.

Okay.

That's first of May

Excuse me, May, sorry.

That reminded me, so you mentioned that you had a comprehensive settlement with multi-party are there, what parties are not part of that settlement or are there any disputed issues that...

In Colorado?

Right.

All the major interveners signed off on it, Dan you always get a few outliers that won't but Dan again, we expect to have a decision out of the Commission today, potentially it already happened. So we should have full clarity on that very shortly.

Okay. Well, thank you.

Thank you.

Good morning, just to be clear on that, just to be clear on the Minnesota property tax proposal; relative to your guidance, do you think you would still have additional room to find offsets if the deferred property tax in Minnesota is not granted?

We said in the call, I think in the absence of the Commission not giving the $24 million, it’s a pretty big hit to overcome. So I don’t think we could get it without sacrificing things that we won’t sacrifice as far as maintenance of the system.

So it would be tough. Now that said, there’s always backup plans and we could ask for reconsideration or we can consider filing our planned rate case in Minnesota early.

Those aren’t the preferred routes, obviously.

Okay, fair enough. And just one other question regarding the updated earning guidance assumptions, were there any changes to your CapEx this year kind of driving the lower depreciation expense and the lower AFUDC equity or is that kind of more a function of the expected regulatory outcome?

We haven’t had any changes yet in terms of our CapEx this year, and while it’s a very small increase, remember in the Minnesota case, we agreed to a $30 million annual reduction in our depreciation expense. So, we’re seeing that reflected in this period, the first quarter’s expense.

It also reflects updates and in-service dates and timings and things like that, that have impact those lines.

I want to thank you all for participating in our first quarter earnings call this morning and if you have any follow-up questions, Paul Johnson and our IR team are available to take your call. So thanks a lot.