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…

(Operator Instructions) And we do have a question from the line of Paul Ridzon from KeyBanc. Your line is now open.

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.

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.

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.

Sure.

Split between gas and NGLs that's what you're thinking or is it…

Yeah, and then, if you had any more color on percentage ethane, propane et cetera?

Got it. Thanks.

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.

Okay and your expectation is still kind of drill the six to eight wells even though you had some issues?

Absolutely.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.