Doran Schwartz - VP & CFO Terry Hildestad - President & CEO Steve Bietz - President & CEO, WBI Energy Dave Goodin - President & CEO, Montana-Dakota, Great Plains Natural Gas, Cascade Natural Gas and Intermountain Gas John Harp - CEO, Knife River Corporation and MDU Construction Services Kent Wells - President & CEO, Fidelity Exploration & Production Bill Schneider - EVP, Bakken Development Nicole Kivisto - VP, Controller & CAO, MDU Resources

Paul Ridzon - KeyBanc Holly Stewart - Howard Weil Timm Schneider - Citigroup John Hanson - Presidus James Bellessa - D.A. Davidson & Co.

Good morning. My name is Alisha and I will be your conference facilitator. At this time, I would like to welcome everyone to the MDU Resources Group Second Quarter 2012 Conference Call. 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) This call will be available for replay beginning at 2:00 PM Eastern today through to 11:59 PM Eastern on August the 16th. The conference ID number for the replay is 93978182. Again, the conference ID number for the replay is 93978182. The number to dial for the replay is 1-855-859-2056 or 404-537-3406. I would now like to turn the call over to Doran Schwartz, Vice President and Chief Financial Officer of MDU Resources Group. Thank you. Mr. Schwartz, you may begin your conference.

Thank you, and good morning everyone. Welcome to our earnings release conference call. And before I turn the presentation over to Terry Hildestad, our President and Chief Executive Officer, I'd like to mention that this conference call is being broadcast live to the public over the Internet and slides will accompany our remarks. If you'd like to view the slides, go to our website at www.mdu.com and follow the link to the conference call. Our earnings release is also available on our website. During the course of this presentation, we will make certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although the company believes that it's expectations and beliefs are based on reasonable assumptions, actual results may differ materially. For a discussion of factors that may cause actual results to differ, refer to Item 1A, Risk Factors in our most recent Form 10-K, and the Risk Factor section in our most recent Form 8-K. Our format today will include formal remarks by Terry followed by a Q&A session. Other members of our management team, who will be available to answer questions during the Q&A session of the conference call today are Steve Bietz, President and CEO of WBI Energy; Dave Goodin, President and CEO of Montana-Dakota, Great Plains Natural Gas, Cascade Natural Gas and Intermountain Gas; John Harp, CEO of Knife River Corporation and MDU Construction Services; Kent Wells, President and CEO of Fidelity Exploration & Production; Bill Schneider, Executive Vice President of Bakken Development; and Nicole Kivisto, Vice President, Controller, and Chief Accounting Officer for MDU Resources. And with that, I'll turn the presentation over to Terry for his formal remarks. Terry?

Thank you, Doran. Good morning. Thank you for joining us today to discuss our second quarter results. Earnings for the quarter were $53.9 million or $0.29 a share. The results included $15 million after tax reversal of a natural gas gathering arbitration charge, as well as $5.1 million income from disposed operation. We also took a charge relating to the gathering assets in our coal bed area of $1.7 million after tax. Well absent these items, we delivered recurring earnings at the upper range of our guidance for the quarter at $0.19. The E&P segment has continued it's impressive expansion of oil production. In fact, oil represented 44% of total production for the quarter. This was up from 30% for the same period a year ago. While the utility group was affected by unseasonably warm weather, primarily in April, and higher income taxes, they experienced significant customer growth primarily in Western North Dakota. In May, we announced our $66 million initial investment in oil and natural gas midstream assets by our pipeline group, and the construction group had a solid quarter and continues to see signs of recovery. On a year-to-date basis, lower oil and natural gas prices affected our E&P group earnings by approximately $20 million compared to last year. And the weather challenges that are utility totaled approximately $7 million. The strength of our diversified business model and the strong execution of our business plans as the operating company has allowed us to partially offset the combined year-to-day $27 million earnings effect coming from these largely uncontrollable factors. Based on our performance to-date, and our outlook for the remainder of the year, we've reaffirmed our guidance of $1.00 to $1.25 per share. Now I'll move on to our individual operations and I'll begin with the E&P business. We continue to see significant oil production growth as a result of our increased drilling activity. Oil production increased 32% over the same period last year, and increased 13% from the first quarter. The jump in oil production was led primarily by the Bakken, where we saw a 59% increase in production over last year. Our Paradox and our Texas properties also contributed to the increase. With continued success developing the Bakken and promising initial results from exploratory areas such as the Paradox, we've raised the midpoint for our oil production growth for the year. We are confident that we will reach our higher oil production goal for the year now estimated to increase from 25% to 30% over last year, targeting oil opportunities. We've also increased the capital allocation of this business unit by $75 million to a total of $475 million this year. On the natural gas side, we have continued with our strategic shift away from natural gas production until prices increase. Average realized natural gas prices were 36% lower for the quarter compared to a year ago. If you recall from a press release we issued in March, we announced that in February we've set a new field production record in the Bakken of over 5000 net barrels of oil per day. Well, I can tell you that for the second quarter we averaged over 5,900 barrels per day. The Bakken remains huge for us and holds substantial room for future growth. We currently have 9 rigs drilling; five of them are located in the Bakken. In Mountrail County we have two rigs operating as we continue to develop our acreage position with a total of 20 wells planned for this year. We also have two rigs operating in Stark County, where we recently put some several wells on production. The cost of Kostelecky 5-8H well came on at 1473 barrels of oil equivalent per day. Raccoons well 25-36H came on at 1456 BOE's per day, and the 2E, 22-15H came on at 1026 BOE's per day. While we had completion problems with our Parker 29-32H well, which still had initial production rate of 655 barrels of oil equivalent per day. We anticipate drilling a total of 14 oils this year in Stark County. And we are very encouraged by the results we see on this acreage. In Richland County and Montana, the first two wells have been put on production. While, it's early in this appraisal process we see significant potential in this area for our Bakken play. We've been busy completing our appraisal program in the Paradox Basin since our last earnings call. The Cane Creek unit number 26-2H, which we previously released test results for continues to be a strong producer. It's still flowing at around 500 barrels of oil per day through significant pressure. Our second and third wells were completed openhole. And based on the results, future wells will be completed using practices consistent with our first Paradox well at 26-2H. In Texas, we continue to develop our acreage as we target areas with higher potential for liquid content. Probably aware that natural gas liquid prices have been under pressure in the recent past. We have been impacted by this lower pricing, however, only 20% of our liquids are natural gas liquids and two-thirds of that NLG. We received a higher amount belvieu pricing on. We recently entered into an exploration agreement in Sioux County, Nebraska. We continue to believe the potential of this play is significant. We've expanded our drilling program with plans to drill six to eight wells in total this year. In the Heath Shale we have had our first two wells on production. Initial results are encouraging although we struggled to maintain constant production because of pump and paraffin issues. We planned to drill a total of five wells there this year as a part of our appraisal program. On drilling three appraisal wells we have the right to exercise an option to purchase 65% working interest in Nebraska, in the 79,000 growth acres in Nebraska. Our strategy of moving to a more balanced portfolio of oil and natural gas is being executed, we believe that our extensive gas properties have great long-term value, of what prices where they are today, we will continue to invest in what provides the greatest return, and right now that's the drilling for oil. We are very encouraged by the performance of our E&P business this year and the prospect of significant and sustainable oil growth over the coming years. Now I'll move on, our combined utility businesses reported a loss of $2 million for the quarter. This loss was primarily the result of mild weather in the shoulder winter months of April compared to a very cold April last year and higher income taxes. For the quarter, weather across our system on average was approximately 30% warmer than the prior year, negatively affecting earnings by about $4.4 million. We're pleased to report that with recent record breaking temperatures in Eastern Montana, and Western North Dakota, and the growth of our system load, we set an all time summer peak electric peak in July, this equips our previous prior peak by 7%. We now have 975,000 utility customers with growth driven primarily by Bakken oil development. Electric customer accounts in the area grew by 8% and gas customers increased by 6% totaling 3900 new customers in that region alone when compared to last year. We plan to invest approximately $75 million this year to serve the growing customer base associated with Bakken. We're moving forward with the preparation of the construction of an 88 megawatt gas fired turban adjacent to our existing Heskett Generating Station near Mandan, North Dakota. In April, we obtained advanced determination of prudence from the North Dakota Commission on this facility. The project will cost approximately $85 million and should be in service in 2015. This facility is necessary to meet the capacity requirements of our customers; it will be a partial replacement for the third-party contract capacity that expires in 2015. We also, in the quarter received advanced determination of prudence for an environmental upgrade at our Big Stone station, our share of the cost of this project is estimated to be about $125 million. So despite the weather challenges this quarter, our utility is doing well. We've experienced substantial customer growth and they have good prospects for continued growth into the future. Recent record breaking temperatures in our electric service territory and higher customer demand have lead to peak loads. Our team is doing a great job finding opportunities to invest in this growing business segment. Next our pipeline and energy service group had earnings of $15.8 million that included the benefit of a reversal of an arbitration charge of $15 million after tax. You may recall that the arbitration case involved a disagreement regarding the terms of operating in pressure of a company owned natural gas gathering system. We indicated, when we took the charge in the third quarter of 2010, that we believe the arbitration decision was not supported by the underlying gathering agreement, that we would aggressively pursue all of our legal remedies to challenge that decision. And we're very pleased with the Appellate Court's decision to vacate the ward and remand the case back to District Court for further proceedings. We believe it should have been there in the first place. The Group saw a 32% decrease in gathering volumes the quarter compared to last year's customers and this was due to some customer curtailments, there were some normal production declines, and we had the deferral of some development activity. In addition, we recorded an impairment related to our coal bed natural gas gathering assets of about $1.7 million after tax in light of the sustained lower natural gas pricing environment. Partially offsetting these items, was higher transportation volumes compared to a year ago resulting from a relatively wide seasonal price basis differential past few months, which has supported storage injection. During the quarter, the company took a significant step towards executing it's strategy to expand in the midstream space with its announcement of the acquisition of a 50% interest in oil and natural gas midstream assets near Belfield, North Dakota. In total, we expect to invest approximately $100 million for our portion in 2012 and that includes the purchase price. The investment includes a newly constructed natural gas processing plant that has an inlet processing capacity of 35 million cubic feet per day, an oil terminal, a natural gas and oil gathering system, and other related facilities. The oil terminal is expected to be completed this quarter. As oil and natural gas production continues to ramp up this investment positions us for earnings and cash flow growth as we move into 2013. We continue to move forward on determining the feasibility of a proposed diesel topping plant in Western North Dakota, purchase options for the site have been executed, and the zoning was approved in early July. This facility would process 20,000 barrels per day of Bakken oil and would employ approximately 100 people. We're looking to complete the final design, engineering, and economic evaluations in order to reach a decision point final decision point on this project early this fall. The pipelines close proximity to the robust energy development areas provides us for exciting outlook as we continue to pursue multiple growth opportunities with this business unit. Now moving onto the construction materials and service companies. We're pleased to report the combined earnings were $5.4 million higher this quarter than a year ago that's a 49% increase. Weather cooperated allowing our materials business an early start to the construction season. We're seeing success particularly at our North Central regions operations, which includes the Bakken area. Across that region volumes of bagger goods, ready mix, concrete, and asphalt, were all up, along with our construction margins. We're in the process of completing ready mix expansion into a couple of additional communities in the Bakken region mainly we're expanding into Watford City and Dickinson. As we look ahead boding well for North Dakota and the Bakken area, the Governor Dalrymple recently proposed to spend $2.5 billion on state roads and infrastructure during the 2013 to 2015 biennium. This funding would be $1 billion higher than the current level and more than quadruple of funding for the biennium ending 2011. The construction business has currently $58 million backlog in the Bakken region and is certainly positioned well to continue to take advantage of growth, the growing demand for infrastructure in this area. If you look at a year ago we had approximately 75 employees at this time in northwestern North Dakota working for our construction businesses. At peak season this year we expect to have between 300 and 350 employees. We're pleased that Congress recently passed a Moving Ahead for Progress in the 21st Century Act or MAP-21 as it's called; it stabilizes transportation programs through September of 2014. This bill includes highway funding levels for 2013 and 2014 of approximately $40 billion per year that's in line with the current year funding. The passage of MAP-21 put states in a much better position for bidding out larger long-term road projects. Our service business continues to perform well, a primary driver of earnings growth was the continued success of the company especially equipment manufacturing and sales and rental division. Additionally our refinery turnaround business successfully completed another project in Billings, Montana, and it's in the planning stages for it's next project in Oklahoma, Texas, and Mississippi. Inside electrical division, we've seen increased bidding opportunities and engineering activity and many other markets that have previously been depressed. We're looking forward to these projects being released for bid throughout the remainder of the year. We're pleased with the results from our construction materials and our services operations. We think the market has bottomed out and we're seeing signs of stabilization. Our combined construction backlog at June 30 was approximately $980 million that includes many high quality projects. Now returning to the consolidated discussions we have overcome significant pricing and weather challenges and managed to perform at the upper end of our quarterly guidance. Our investment in the E&P business continues to deliver impressive increases in oil production. With the strength of our balance sheet, and the access to liquidity we were able to authorize an additional $220 million in capital spending for the E&P, the pipeline, and the utility groups combined. We did this without issuing equity. We added significant liquid based midstream assets at our pipeline and our construction group continued to build momentum with a good start to the material season. Our businesses are performing today in investing for the future to benefit our shareholders. As a remainder, we also provide a competitive dividend with a current yield of approximately 3%. So with that thank you for your time today. We would be happy to open the lines up now operator for questions. Operator?

(Operator Instructions) And we do have a question from the line of Paul Ridzon from KeyBanc. Your line is now open. Paul Ridzon - KeyBanc: Just got a quick question regarding guidance and the arbitration award. Does the guidance include that arbitration award, is that excluded as a special item?

You know Paul if we look at it, our guidance we would be within our guidance with or without the award, as we are forecasting the rest of the year.

Your next question comes from the line of Holly Stewart from Howard Weil. Your line is open. Holly Stewart - Howard Weil: Couple of questions for Kent on the E&P side. Kent can you just talk a little bit about what you're seeing in South Texas in terms of the NGL breakdown and what are we talking about from an NGL standpoint and then what is your processing solution there?

In South Texas, Holly, we have a lot, we're with the marketing company that has long-term arrangements there. So clearly we're seeing softening of the prices it gets in Mont belvieu pricing but we're not seeing as curtailment of any production or ability to sell our products and we don't process it, but we get our value from both the gas and the liquid. Holly Stewart - Howard Weil: Okay. Do you know what the breakdown midstream is?

Let me get back to you on that to make sure. I have an idea but I want to make sure I get the right number. So we'll get back to you on that. Holly Stewart - Howard Weil: Sure.

Split between gas and NGLs that's what you're thinking or is it… Holly Stewart - Howard Weil: Yeah, and then, if you had any more color on percentage ethane, propane et cetera?

Got it. Thanks. Holly Stewart - Howard Weil: And then on the Paradox you talked a bit about completing a couple of wells differently than the first well. So if you can just give us a little bit more color there?

Sure. So on our first well if you remember we drilled about 1000 foot of horizontal, lateral. We only perforated the last 100, 200 feet of the lateral, came on very strong. In fact today the well is still flowing around 500 barrels a day at £900. We're estimating the EUR in that well probably going to be about 0.5 million barrels. In order to connect more of the reservoir and connect all the factor systems we decided on the next two wells to go openhole completion. About 10 years ago we had successfully pulled a liner out of the well that has been drilled long time before that and we just thought that that would be the far more effective completion technique. We now regret that decision. So the second well is probably, its EUR is going to be closer to about 300,000 barrels. The well is not as strong. We did some testing on it. We've clearly got some damage. I think part of our problem is we drilled it with such heavy mud weight, getting the heavy mud weight to flow out of the horizontal is problematic for us. And in the third well, which from all drilling and initial completion attempts, we're going to just see by far, that well has very high pressures, which constantly trying to flow and when we initially put it on production it started to flow very strong and then abruptly stopped. And then we went back in, in the well bore, a horizontal piece had collapsed. So we're going to have to go back and re-drill that in and tape that which we will do with our current rig line, and it will be just a couple of wells down the way. So what we've done here is we're still extremely encouraged in the Paradox. But it's deferred our production growth a little bit there. But everything we're seeing still has, is very excited about this play. Holly Stewart - Howard Weil: Okay and your expectation is still kind of drill the six to eight wells even though you had some issues?

Absolutely. Holly Stewart - Howard Weil: Okay.

We're just continuing to go and we're mapping out a multiyear program and we're looking at pipelines and everything. It was just we thought that the better completion technique we fell could hold on and that was wrong. Holly Stewart - Howard Weil: Okay. Sounds great and just a little, a few comments on Nebraska. Haven't heard much about a play there, so just kind of initial thoughts?

Yeah so we're encouraged here. We've entered into an exploration agreement, a type of agreement we like where we're not required to put a whole bunch of money upfront. We're going to drill two vertical wells followed by a horizontal well. It is targeting oil. It's of significant size. We'll talk more later in the year along with our partner there to disclose more details of it. But we have, we've finished drilling our first vertical well. We're in the midst of drilling our second and we'll shortly be completing our first. And so I would think more in fourth quarter will be able to give more details about that. There is some other opportunities to expand in the area and we're just not saying a lot at this time. Holly Stewart - Howard Weil: Okay, great. And then may be just one on both construction groups if I may, looks like the revenue numbers and guidance have gone up. Is that just a function of a better than expected second quarter or is there something more to it?

I think it's obviously a little better expected second quarter. It was obviously as nice to see our top-line revenues were growing in both construction groups. And obviously our net is improving. So we're happy where we're at and we're hoping for the best for the next six months. Holly Stewart - Howard Weil: Okay perfect and then just one final one on the pipeline segment. Any color in terms of the financial impact of this midstream acquisition for the second half of the year?

Holly, this is Steve. If we kind of look at that today and we're still seeing volume has ramped up in for that plant. So it's not at full capacity. Once its there it's about 35 million a day. We're probably run around a third of that today. So as you look at the financial effects this year kind of contribution to earnings will be somewhat minimal. But as we get into next year it will provide an attractive return on our investment. Holly Stewart - Howard Weil: And is that -- those are all fee-based contracts?

Some are fee based some are percentage of completion. So we've got a little of both. The other thing I should mention we've got an oil terminal that's part of that acquisition that should be kind of up and running later this third quarter.

And your next question comes from the line of Timm Schneider from Citigroup. Your line is open. Timm Schneider - Citigroup: Hey first question, looks like the realizations on the crude oil side, the unhedged portion was about a 23% discount to WTI and 17% discount to Clearbrook. Just wondering what was causing that differential and how you see that progressing kind of through the rest of the year?

Yeah, Timm, this is Kent. First a good chunk of our oil production comes from the Bakken and that's where we saw the biggest decrements on the differentials. As we look at the differential for the second quarter what we call the Bakken differential average, a little over $15. Now that includes $6 per trucking. That compares to $5 to $6 differential a year ago. So there is about $10.00 incremental drop there. s: So, I think it's hard to sort of predict what's that going to be over the next six months. And then, I think hopefully, in the next several quarters as our Paradox production becomes more significant, we're not dealing with that in the same way. Timm Schneider - Citigroup: Got it. And then if you can jump to your Stark County real quick, I noticed you up the spacing to 1280 from 640 and kind of cut your drilling locations to 40 from 140. Just wondering what was driving that?

Yeah. So when we initially talked about it, we really didn't have any wells there. And what we like to do is when we first go out and do our exploration appraisal we drill 640. And now, that we've drilled a few wells and we're confident we can drill 1280 wells, they're more attractive economically to do it. So, what we've done is we've moved from we call them -- initially we're talking about 140 gross potential locations. So, those were the number of locations we had. We would obviously cut that number in half just by going from 640 to 1280. So what we're actually talking about now is -- these are the drillable locations we actually see that were -- we've got on a drill plan that we're going to drill and that number can continue to grow as we drill more wells and fell more confident with some other areas. So, we're actually very pleased on where Stark County is going. We've drilled some attractive wells there. The costs are likely in the QC and most notable. Timm Schneider - Citigroup: Got it. And then, I do not know if this has been asked or not, I jumped on a bit late. With respect to be Niobrara the four wells you outlined. I mean, I guess it was your target for the rest of the year too. Is there -- because planning they do anything more there or was that kind of it?

Yes, on the Niobrara we drilled three horizontal wells and one vertical well and they were disappointing results. We didn't see results that wanted us to continue on with what we were doing. We're studying two things right now. We're looking at our completion technique and the technology available and did we miss the trick that might make that area the Niobrara work. And then, also when we drill those wells, we came across two other horizons that looked quite encouraging. So, we're doing some G&G study work on those and that will take at least through the end of the year and into next year before we decide next steps in the Niobrara. Timm Schneider - Citigroup: Got it. And what's the remaining CapEx for the kind of the Belfield gas plant for remainder of the year or within that joint venture with Whiting?

Our initial investment there Tim was about $66 million. By the end of the year we should be including that investment right around the $100 million.

(Operator Instructions) Your next question comes from the line of John Hanson from Presidus. Your line is now open. John Hanson - Presidus: Just a one question here on your Bakken area your neighboring ones up. I know you folks have talked about having some water issue, are you guys doing okay on that?

Yeah, this is Kent. We -- we're sufficiently have the water we need to do our fracs and we have our disposal needs taken care of. So right now it's not an issue for us. John Hanson - Presidus: Overall well costs are holding in line or up down, how is that going?

We've made some really good improvements over this quarter on our well cost. Remember last quarter, we talked about that the cost had moved up to the $8 million to $9 million range. We've been able to bring those back down into the $7 million to $8 million range. And it's a few different things. First of all, we worked on that on the market, so we definitely reduced our fracking costs quite significantly. We worked on all the other supply costs as well. And then, we've made some real improvements in how we actually drill the well. We now use a mud rig to drill our surface casing that allows us to drill wells quicker, and at lower cost. We've improved all aspects of drilling most notably was we're drilling the lateral. We now, rim and drill at the same time. So we're doing 1280 wells in less than 30 days typically around 28 and we're getting our 640 wells down below 20 days. So it's all round improvement and in terms of performance and working the cost, and we feel very good about getting down below $8 million a well.

And we've another question from the line of Timm Schneider from Citigroup. Your line is open. Timm Schneider - Citigroup: Hi, guys. One more question. Real quick on the E&P CapEx going up $75 million. Can you just help me reconcile that? If I just look at the releases quarter-over-quarter, I think it's an incremental 55 foot of Bakken and incremental 25 foot of Paradox and an incremental 20 million foot of Heath, it's around a $100 million there, not including the exploration play. So, I just assume that the delta is just lower CapEx in the natural gas side?

Yeah, Tim, great question, and you're absolutely bang on. The additional capital is going to where we're having success. So it's going into the Bakken, it's going into the Paradox. The Heath play actually is kind of interesting at this point. We've drilled three wells. We've got our first one on production the Schmidt well and initially flowed about 360 barrels a day and that was a three day average. And then we put it on pump and over a 14 day period it produced about 260 barrels a day. Since then we've had a lot of plugging problems with our pump and our pumps going down. So they don't have big consistent data on that and we're just getting our second well on production as we speak. But we've been able to take our well cost. Our first well actually cost us $8 million to drill and we're now drilling them, drilling, completing them and put them on production for $4 million. So that has really brought that play to be of much more interest to it. We still want to get the rate and reserves up a bit. We're working on our completion technology there. So that's why you're seeing potentially some more money going there. But our philosophy is the money is going to go to where we see the economic success and so it's not only are we getting good production results but what are the prices we're seeing. Timm Schneider - Citigroup: Got it. So if you can just -- can you quantify what your spending on gas if anything in 2012?

Yeah, the only place we're spending on gas is in South Texas and even that's an overstatement because we do get oil and condensate with that production and it's very rich gas. So you could debate whether we're spending any money on gas. But that's we only have one rig that's targeting gas in any way shape or form. Timm Schneider - Citigroup: Got it. And then have you guys disclosed to your exploration agreement this with?

We have not.

And your next question comes from the line of James Bellessa from D.A. Davidson & Co. Your line is open. James Bellessa - D.A. Davidson & Co.: You mentioned that there was a charge for natural gas gathering assets and that was for coal bed methane activities. Did you move the coal bed methane activities from Fidelity over to your pipeline and energy services business or were these just purely gathering assets that had already been there?

Jim this is Steve. Those gathering assets have historically and continued to be at WBI Energy. So there nothing was moved from Fidelity. James Bellessa - D.A. Davidson & Co.: And when you did your coal bed methane activity several years ago were they all always at WBI or were they ever at Fidelity?

See all of the gathering assets and all the pipelines were at Fidelity. Pardon me, were at WBI I'm sorry.

And this marks the last call for questions. (Operator Instructions) This call will be available for replay beginning at 2:00 p.m. Eastern today through till 11:59 p.m. Eastern on August the 16th. The conference ID for the replay is 93978182. Again the conference ID number for the replay is 93978182. At this time there are no further questions. I would now like to turn the conference back over to management for closing remarks.

Well thank, thank you very much. We will keep you updated as we move through the year as we always do. This is third quarter is a big quarter for our company, certainly our construction operations. We appreciate you participating on this call today and we look forward to speaking with you again soon. So thank you for your interest in MDU Resources.

And this concludes today's MDU Resources Group conference call. Thank you for your participation. You may now disconnect.