At this time, I would like to welcome everyone to the MDU Resources Group second quarter 2013 conference call. (Operator Instructions) I would now like to turn the conference 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 welcome to our earnings release conference call. 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 our 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 its 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 Form 10-Q and the Risk Factor section of our most recent Form 8-K. Our format today will include formal remarks by Dave Goodin, President and CEO of MDU Resources, followed by a Q&A session. Other members of our management team, who will be available to answer questions during the Q&A session in the conference call today are: Dave Barney, President and CEO of Knife River Corporation; Steve Bietz, President and CEO of WBI Energy; Nicole Kivisto, Vice President, Controller and Chief Accounting Officer for MDU Resources; Frank Morehouse, President and CEO of Montana Dakota, Great Plains Natural Gas, Cascade Natural Gas and Intermountain Gas; Jeff Thiede, President and CEO of MDU Construction Services Group; and Kent Wells, Vice Chairman of MDU Resources and President and CEO of Fidelity Exploration and Production. Now, before I turn the call over to Dave, as we stated on our first quarter earnings conference call, following industry trends we discontinued the use of hedge accounting effective April 1. And as a result, perspective non-cash changes to the fair value of our commodity derivatives now have non-cash impact on the income statement before they were recorded to the balance sheet. In addition, we move to a format of presenting our earnings on a GAAP basis as well as on an adjusted basis, netting out certain one-time or non-cash items such as the changes in value from our commodity derivatives. Dave will focus on the adjusted earnings in his remarks today. However, we have provided reconciliations to GAAP earnings in the slides accompanying this webcast and in yesterday's press release. Now with that, I'll turn the presentation over to Dave for his formal remarks. Dave?

Thank you, Doran, and good morning. Thank you for your interest in MDU Resources and for taking time today to join us to discuss our second quarter results. Building on a strong first quarter, we continue to see growth in our second quarter. Consolidated adjusted earnings for the quarter were $47.2 million or $0.25 per share. This compares to $32.5 million or $0.17 per share in the second quarter of 2012. The beginning of summer saw a significant activity across really all of our lines of business. Fidelity produced an all-time quarterly record of 1.2 million barrels of oil, up 37% increase over our prior year. At our utility group, customer counts continue to grow by 7% and 6% respectively for electric and natural gas in the Bakken area year-over-year last year. The pipeline group had over a million yards of material move at our diesel topping plant site. And at the construction group, we overcame really a very wet start to the season and posted a strong quarter and is well-positioned for the remainder of the year with higher backlogs. Now, let's move on to individual operations, beginning with our E&P business. Adjusted earnings for this group were $24.8 million compared to $15 million just a year ago, a 66% increase. This increase resulted from improved pricing for both oil and dry gas as well as a substantial increase in oil production. This was our best second quarter since 2008, when prices were really very much higher. Leading the way to our record oil production this quarter, were both the Bakken and the Paradox Basin plays. Our Bakken oil production increased 42% and production in the Paradox nearly quadrupled year-over-year. We have subsequently moved our oil production growth target higher to an increase in production in the range of…

(Operator Instructions) Our first question comes from the line of Matt Tucker with KeyBanc Capital Markets.

My first question relates to the wet weather that you saw in North Dakota during the quarter. I was a little surprised that there maybe wasn't more of an impact in some of your segments. You kind of briefly did mention it with respect to the construction segment. Just hoping you could elaborate a little bit, whether you saw impacts, and if you can quantify that at all?

Matt, I'll turn that over to Dave Barney, who heads the materials division.

It did effect us in the Midwest, especially North Dakota, Montana. It's just didn't impact our construction, it impacted material sales. As far as giving you an exact number, that'd be hard to do, but if the weather holds, we'll be able to make that up, and it's definitely in our backlog, Matt.

It sounds like even there wasn't much impact on the E&P side?

We did see particularly earlier in the quarter, it really affected our service rigs operations. And we did have some production offline. But towards the end of the quarter, we had really, really strong production growth until that met our expectations for the quarter.

And Kent, could you comment a little bit on the well costs for the well that was drilled during the quarter in the Bakken and the Paradox?

In the Bakken, and I'll give you a year-to-date numbers, if you're okay with that. In Mountrail County, we continue to make the improvements there versus a year ago. We've got a well cost down about 15% in the range of $7 million to $7.5 million. In the Stark County, we're in the range of $7.5 million to $8 million and once again down about 10% to 15%. In the Paradox, the well cost, because we've been starting to do a longer completions in it. And given this better rig well, a well cost is about $9 million and that's down from between $10 million and $11 million from previous year.

And one more question, and I'll jump back in the queue. On the diesel refinery EBITDA projections, could you talk a little bit about your assumptions underlying that with respect to commodity prices or crack spreads, however you may be looking at it?

Yes. Matt, I don't know, I'll ask to Steve to cover that. But I'm sure, I think he is going to say, we're going to not get into real specifics, but I'll ask Steve, if he'd be wants to add anything more to that.

Dave, you pretty much covered. This is Steve, we've just lost debt. And as you would expect, I am trying to consider the markets for our three different products that we expect to come out of the plant. We looked at kind of these receipt quantities and processing cost and that. And so there's lot of assumptions under there. And we're not prepared to get into that. But that's all driven our $70 million to $90 million of cash flow coming from the total facility.

Our next question comes from the line of Holly Stewart with Howard Weil.

Let me first, I guess, touch on the E&P side. Kent, maybe if you could give us first quarter production numbers in the Paradox, so we can just see the sequential ramp that we've got going on?

Well Holly, as you know, we're very excited about the Paradox. And it just continues to grow for us. If we look at it on just a cumulative production in the first quarter, I think we were just shy of 150,000 barrels total production there. The second quarter, we were over 200,000 barrels around 210,000, I think was the number. So you can see it's a pretty significant uplift from first quarter to second quarter.

And then you mentioned in the release permits would be your kind of hindrance, I guess, to a ramp up in activity. Can you talk about permitting levels and what you need to do there to kind of get those permits in line?

Yes. I think one of the things this play has been a play that has worked at our industry for the number of decades. And we're trying to be just incredibly disciplined with what we're doing here. And so we haven't jumped out and permitted 50 or 100 well, so we have this huge backlog in front of us. But as we've started to understand the play and nowhere we need to go, then we need to build up a backlog, what I call ready-to-drill locations, which means not only we decide that where want to drill, but they're also permitted. So we're going through that process with the BLM. And we will, I think, in due course get a backlog that will then make us feel more comfortable with moving beyond the single rig program. We're anticipating that to happen in the first half of next year.

And then maybe just specifics on the second half of 2013 well count?

For the Paradox?

Yes.

Well, it takes us about 45 days to drill a well. Another week, call it, to move from well to well. So you could sit there and go, well, gosh, then that's about three more wells by the end of the year. Maybe we can push that closer to four, but it's in that range. As long as we stay with one rig, so you know why I'm anxious to move beyond the one rig program, because we can really start to accelerate our production, but we've got to get the inventory build before we can move forward with that.

And then one final on the Paradox, I know it's early; any indication on spacing at this point?

That is a really good question. And when you look at the recovery that we're seeing or anticipating forecasting from the 12-1, we're really trying to understand what the drainage pattern is going to be. And it could be that there is a fair amount of variability to it. So really don't have a good answer for you, but it is something we're looking at quiet deeply. And we'll probably need to drill another dozen or so wells, before we have a better idea what that's really going to be.

And then just one on the Bakken. Have we drilled a Three Forks test yet in Mountrail County?

We had drilled it, and we'll be completing it later this month. And we will be experimenting with some of the newer technology that all of us in the industry are looking at right now. So we'll be encouraged to see what happens with that well. We will know by this time next quarter.

And then maybe for Steve or Dave, on the pipeline business, your big long-haul pipeline project. I guess maybe just talk about how this project came about, and then what type of interest level you guys would feel comfortable with moving forward on the project.

It something, we have been looking at for quiet a while. And one of the largest reasons is the increase in gas production, kind of associated production in the Bakken play. And so that gas, we're going to get produced as oils developed up here. So looking for some other outlets, today that gas can go out of the area through northern border, through alliance. Both of those pipes tend to be, are pretty much full today, so really looking at a new market. We've looked at some different routes and different things there. We have, kind of, laid this out to pick-up some load potential in Eastern North Dakota, as well as, kind of, the Fargo market and into Minnesota, into the Viking System. I guess, I'd say, we have been encouraged by the reception. I think there is a view that there is going to be a need for additional takeaway and diversification to move some of the gas production North Dakota. We're working on hard to, kind of, continue to market the project and listen to the feedback we've received from our customers. As far as what commitments we're going to need, it's probably a bit early. There is a lot of factors there, when you think of various contractual terms. You think about just the term of the agreements, the volumes, the rates. So we're going to, kind of, work through the process before we come up with something more definitive there. Obviously, we are looking for longer-term contracts associated with that project.

And then any, I guess for Dave, big picture thoughts around ways to use the integrated model for this project?

Certainly, Holly, as we've touched on in other quarters and even in our small group meetings, talking about leveraging across our businesses. We've highlighted helping out well pads at Fidelity through our materials group. The refinery, I think, highlights all business lines having a hand in that. I would say, we were just trying to see some momentum, when you think about this kind of a project. We've got environmental permitting regulatory experience at a number of our business lines. We've got construction expertise and knowledge as well. We're probably going to need, one would likely think, a number of spreads when you put this, we say, we're going to build this in one construction season. It's probably not going to be just with one contract there as well. So I think it's got potential, plus we have some of the intelligence that we gather through our E&P group as to the oil activity and the drilling activity going out on west as well. So I think it's inherent with some of all of our lines of business, a project like that. I would also mention that the $650 million to $700 million, we've indicated to the project scope would be like this, is not included in our five year capital program of $3.9 billion. And so it really goes above and beyond that from an investment perspective.

And then just one final one for me, I promise, I'll stop. The last question asked about the assumptions around the EBITDA from the refining project, any idea, Doran, on timing for providing some of those assumptions? Could we see them at the Analyst Day?

Holly, where we're at right now is providing the guidance that's out there, $70 million to $90 million. I would say that's little uncomfortable at this particular point. But obviously, we view this as a very strong project with reserve potentials on a $70 million to $90 million EBITDA for a $300 million (inaudible) payback is very strong. There are three products that Steve talked about that these all are the pretty transparent markets, and the import side for the crude is pretty transparent. Naptha is somewhat of a transparent market, too. And ATV is something we feel good about, our agreement there in terms of the offtake of ATV side. I think in terms of economics that is, much as I can, maybe help you in terms of trying to evaluate that input on the crude side relative to the economics will come off the back-end of the plan for those two types of business.

Our next question comes from the line of Chris Ellinghaus with Williams Capital.

Can you characterize the quarter from the LDC side? How close to normal did it look?

Frank, do you want to take that one.

The gas side experienced, all across our utility, we actually experienced for the quarter a little cooler than normal temperatures. But you have to put that in perspective, the quarter isn't the greatest quarter for heat load within the gas segment of our business. That cooler weather, had then also led to a little bit lower on our electric sale side. So all in all, it's a quarter that is fairly typical. The weather pattern definitely impacts our ability. We look forward to continued normal weather program and pattern through the rest of the year.

Doran, the other segment has been, sort of, producing small income pretty consistently. This quarter it was little different. Can you talk about where that came from?

Chris, our Chief Accounting Officer, Nicole Kivisto, is ready to address that question.

Chris, basically we've got a number of items going through there, of a small nature. We've got our captive insurance program. We've got a small investment in international assets. And then we also have company profit going through there this quarter. And so in terms of the delta between last quarter and this quarter, the difference is really the intercompany profit. So as you have heard us kind of talk about leveraging across our businesses. That really is the driver, been in terms of intercompany profit.

So it's just something that evens out across the segments then?

Correct. Yes. So the profit is recorded at the segment level and then eliminated to get to consolidated.

Kent, can you talk a little bit about what you have been doing with your shut-in gas production?

Just as a reminder, in May of 2012, we shut-in, in the neighborhood of $20 million cubic feet a day in our Baker and Bowdoin as a result of low gas prices. At that point of time it was about $2. In the first part of June of this year, we started return some of that production back on, and I think now we've got in the range of maybe $10 million to $12 million cubic feet a day back on production. And we'll continue through the rest of the summer ramping up more of it. I'm not sure we'll get to the full $20 million, bring back on, but we'll bring a good chunk of it on. In anticipation of that, we actually went ahead and hedged some of this production from September forward at $4.13. So we sort of feel good about shutting it in and then turn it around and how we're bringing it back on it, at double the price.

Dave, you sound a lot more optimistic on construction. Can you just give us a little flavor for what you are thinking?

Well, certainly. I think the backlogs almost speak for themselves. We're in a $2 billion on a combined basis. You heard the question early about the wet spring and may be a little surprise at still how well some our materials group did. In my comments, I mentioned Northern California, Dave Barney, mentioned the Intermountain region. I mean, we have a presence down in Texas. I think it also helps to kind of show some of the geographic diversity that, while, we did have a record wet weather that was negatively affected North Dakota, parts of South Dakota, Montana, some of that diversity is helpful there. On that construction services group, we mentioned across all lines of business had a good quarter. And while we do some outside line construction work, we've had inside line of business. We do industrial. We've got our materials, and our rental, and our leasing business, so far as what we have got there for transmission line. So I, kind of, like the diversity. And I also like the backlog. I think a real key for us thinking about going forward is all that backlog, how much cooperating weather we might get in that early fourth quarter. I really like our view right now. We've had a nice string of a very conducive weather for our construction businesses, really in all of our markets. So I don't know, but that's sounds optimistic. I think that's very realistic. But I really like our backlog. And topline has actually shrunken some of our construction and the bottomline is growing. And that some of that cost containment in the savings will realize though the middle part of the income statements. So it's attribute to Barney and his team, and Pete and his team, I would say.

And you were talking about the mix increasing on the private side. Do you see that as a trend that will continue?

Certainly, I think we peaked out back in mid-2,000s at almost 40% private. So it's really got a long way to go, to get to there. But I like the movement we've seen from between 8%, 9% a year ago to now 13% on the private side. So I'd like to see maybe a little bit that way, but, kind of, measured growth there is fine. And again the backlog is strong. So the mix is nice moving in the private way record DOT budgets in North Dakota are, kind of, right in our backyard, as well. So we kind of like all of those opportunities.

Our next question comes from line of Matt Tucker with KeyBanc Capital Markets.

Just a quick follow-up, it's tough to find much to nitpick on here. But I did notice the construction services backlog ticked down a bit sequentially, bookings down by a bit more sequentially. What should we read into that, if anything? And if you do expect that trend to kind of reverse going forward, maybe could you comment on what end-markets you are most optimistic on going forward?

We are very confident. As Dave mentioned, all of our areas are up as far as performance. On our backlog, we see increased opportunities in the outside line construction, especially in the west and Intermountain regions. Our inside businesses in the manufacturing sectors are also strong. We also see our equipment and supply business improving as well and also industrial. So all segments, we see with strong opportunities in market gains. We are confident that our teams are positioned, ready for growth, and then also to be able to execute the work profitably, so all areas that we're seeing are strong. And we've got the people ready and positioned, and the financial backing to execute.

(Operator Instructions) At this time, there are no further questions. I would now like turn the conference back over to management for closing remarks.

Well, again, we appreciate your interest in MDU Resources and for tuning into today's earnings call. We're certainly pleased with our performance year-to-date. And we continue to be focused, really, though, on execution, executing the growth opportunities that are really right in front of us. I see all of our business units are working together to add shareholder value. And again, we appreciate your participation on the call today. And we'll keep you updated as we move throughout the year. And maybe just as a reminder, we do have an Analyst Day scheduled in the Portland for September 18, actually 19, is the day for the presentations. If you're able to make that trip, we'd certainly invite your participation. And again, thank you for your interest in MDU Resources.

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