Good morning. My name is Sarah and I will be your conference facilitator. At this time, I would like to welcome everyone to the MDU Resources Group 2013 Year End and 2014 Guidance 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 1 PM Eastern Time today through 11.59 PM Eastern Time on February 18. The conference ID number for the replay is 29265471. Again, the conference ID for the replay is 29265471. The number to dial in for the replay is 1 (855) 859-2056 or (404) 537-3406. 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 would 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 Factors section in 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 of the conference call today are Dave Barney, President and CEO of Knife River Corporation; Steve Bietz, President and CEO of WBI Energy; 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; Kent Wells, Vice Chairman of MDU Resources and President and CEO of Fidelity Exploration and Production; and Nathan Ring, Vice President, Controller and Chief Accounting Officer for MDU Resources. And with that, I will 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. We are excited to be here today to discuss our 2013 results as well as our 2014 outlook. 2013 was a very successful year for MDU Resources and its shareholders with each of our businesses segments contributing to that success. Our construction business has led the way continuing their strong resurgence surpassing $100 million in earnings for the year for the first time since their combined record year of 2007. Fourth quarter marked the ninth consecutive quarter of year-over-year earning improvements for the group. Our utility had a record fourth quarter and the year of continued growing past 1 million customers throughout year. The performance was largely a result of continued strong customer growth led by activity in and around the Bakken and significantly colder weather across our service territory during the winter months. The pipeline had a solid year with the full year benefit from the Pronghorn assets that were purchased in May of 2012. Our E&P group had great results on the strength of a 30% increase in oil production compared to the prior year. Further progress was made balancing its production portfolio with oil now representing 47% of total production in 2013, approximately double what it was in 2010. These combined business unit successes resulted in adjusted earnings for the year of $289.9 million or $1.53 per share compared to $218.9 million or $1.16 per share last year, up 32% increase. And shareholders received a 48% total return on the year. Now I would like to turn our attention to a more detailed look at the results of our individual operations beginning with our Construction business which posted earnings of $103.1 million in 2013. Earnings grew by 46% over the prior year on…

(Operator Instructions) Your first question comes from Matt Tucker, KeyBanc Capital Markets. Your line is now open.

Hi, good morning and congrats on a great year.

Good morning, Matt, thank you very much.

First question on the natural gas production guidance, it’s been down 20% or 30% in ’14, is that a drag on earnings growth in ’14?

Hey, Matt, it’s Kent. The real reason production is down as much as the divestments we made in ’13. If you recall Dave mentioned we made $84 million worth of divestments and a lot of that was gas and the most notable two-thirds of that was our Green River Basin asset which we sold right at the end of the year.

I guess what I am kind of getting that is was your natural gas production profitable in ‘13?

Yes, so was that natural gas was a positive cash, but kind of a – I will call it kind of neutral on the net income side. So that’s not the big factor. I mean to be honest with you for the E&P side, the bigger factor is our increasing DD&A which of course is not a cash item, but is a net income. And we are seeing about a 17% or 18% DD&A increase as a result of our full cost accounting and because we divested some low value reserves. It affects the DD&A calculation, if that makes sense to you.

Got it. Thanks Kent. That was very helpful. And then on the construction side, I guess I was kind of surprised, your guidance is the midpoint kind of flattish versus 2013 for the construction segment, while the backlog I guess on a combined basis was up about 25% year-over-year, so I guess could you just give us a little more color on what seems to be a little bit of disconnect there. I know you have to book and burn a lot of your work as the year goes on, I guess maybe are you expecting kind of slowdown in awards?

Say, Matt, I think we will ask Dave Barney to touch on that from the materials perspective and then after him, we will have Jeff Thiede talk about it from the services side, is that fair?

Sounds fair, Matt this is Dave with Knife River. In 2013 we saw good margin increases during the – on the material side and with our higher backlog levels in 2014, I am optimistic we will maintain or increase our margins and earnings in 2014.

And Matt, this is Jeff from Construction Services. We are coming off a record year in 2013 where we experienced above average margins. We are optimistic about our opportunities in 2014. We are a competitive group and we went into 2013 as we do every year and that is to beat plan and beat best ever results. And we do that from focusing on safety and financial. We see markets improving and our operating companies are in a strong position to offer our customers great values in our markets.

Thanks guys. Last question, January was pretty cold in a lot of country and you mentioned some weather impacts in December from I think kind of similar weather, so can you maybe comment just on how January has been from weather perspective?

I’ll start off Matt then we can dive into maybe Frank with utility, but clearly it’s – I think it shows some of the diversity strength we have within our organization. And I will go back to December where Kent had mentioned about our well production challenge in the Bakken whereas we – that certainly is an offset from our utility business. I would say that really continued into January. Frank although given we are in over eight states, not all areas were colder than normal.

That’s correct, Dave. We did see January start off colder than normal, especially in the Dakota area, the typical Montana-Dakota and that helped us on both the gas and electric side actually. We also saw colder than normal temperatures within the Intermountain service territory. But we were right out normal, maybe in fact a little warmer than normal out at Cascade. And so again, our diversified footprint across eight states I think is going to add strength to us as we go through the year.

Thanks guys. That’s all I have for now. I’ll jump back in the queue.

Okay. Thank you, Matt.

Your question comes from Chris Ellinghaus of Williams Capital. Your line is now open.

Hey, guys. The gas sale, was there any gain or loss on that?

Chris, this is Doran. As far as the sale of the natural gas property, the accounting under the full cost method essentially what you do is you reduce your property balance essentially as opposed to booking or a gain or loss, it’s a nuance of full cost accounting for oil and gas, so answer is no.

Okay, great. And you were saying that the Paradox acquisition was right at the end of the year, I assume that was in December sometime?

Hey, Chris, it’s Kent. Actually, we just closed it last week. So it’s actually in this year’s numbers.

Alright. And can you give us a little color, Kent, on the decline in gas production that you are expecting, how much of that is related to the divestiture?

Yes, I don’t have the exact numbers in front of me, a significant amount of that is, but Chris what we have to remember is we are continuing not to invest in our gas assets. So we are going to see that typical 15% to 20% decline and then with what we divested as well.

Okay, that’s good color. And can you give us a little color on what you gave us for guidance on liquids as well?

Well, on the liquid side, we are going to continue to invest in the Bakken and the Paradox are big places approximately 70% of our capital is going to go into those areas. And then what that has said is our Cedar Creek asset, which is where we have the net profits interest. That continues to decline and we have some other oily assets that decline a little bit, but we will figure the biggest percentage growth from the Paradox and then the Bakken, it’s level of growth is going to be depend upon what we do with our new completion techniques that we are still working on.

And one last thing as far as the FERC pipeline case goes, can you give us – that’s a substantial number, can you give us a little feel for what the earnings impact might be from that case?

Chris, this is Steve. I guess where we are at right now, Chris, that’s our file position. We have included a number of assumptions within that case. As we go forward, we are going to work through that. We are currently in the process of responding to a number of data requests that FERC and others have requested of us. We actually have the FERC staff that will be out at our site here or onsite later this month to do an audit. And then we will work toward that implementation data of May 1, our whole peers that were able to settle the case at some level acceptable to our customers and us as well. And we will just have to get through that process before we can identify the specifics of the earnings impacts going forward.

Okay, great. Thanks. Thanks a lot guys.

Thank you, Chris.

Your next question comes from Paul Patterson of Glenrock Associates. Your line is now open.

Good morning.

Good morning Paul.

I want to touch base with you on the just a few quick ones, the commodity derivative gains what was the impact on that for the year, the realized ones?

On the realized gains, Paul?

Yes.

Okay. Just a moment please.

Why you guys are looking that up? If you could remind me why construction depreciation went down, depletion, depreciation and amortization went down?

Paul, this is Doran. Essentially as you know with the Construction Materials business, we have been investing roughly $35 million to $40 million of CapEx over the past several years, our depreciation rate is higher than that. So as the PP&E balances declined down over the last several years as we’ve right-sized our fleet, we’ve sold off some assets, we’ve reduced our invested capital balance, that’s also brought down the depreciation. DD&A is not just the amortization or depletion of aggregate reserves. It’s also the depreciation of the fixed asset balance which probably has more impact than the depletion of aggregate reserves. And so that’s why you’re seeing it dip a little bit in the fourth quarter and for the year.

Okay. And there was no adjustment or anything; it was just a result of lower PP&E?

Yes, that’s correct and it essentially continues the trend that we’ve seen here over the last several years.

Should we expect that in 2014 as well?

Yes, based on our CapEx balance in 2014 of $38 million and a depreciation rate of $75 million if that were to hold true we’d see continued downward pressure on the depreciation rate.

Okay.

Paul, this is Kent. Your question on the realized derivative gains, and as you know, we do our hedging to sort of manage risk and keep continuity. And we had positive hedge gains in first, second and fourth quarter offset by negative in the third quarter and at the end of the year it was almost a complete wash. I think we were $200,000 to the positive with our oil derivatives were just slightly negative and our gas derivatives just slightly positive and overall positive of about $200,000. So we were effective in doing the risk management that have kept a consistent year but at the end of the day we didn’t make or lose money.

Okay, great. And then you mentioned a – also just the gain on the sale of the appliance business at the utility, that’s mentioned in the release. What kind of impact did that have?

This is – this is Frank with the Utility Group. That was really non-material impact to total earnings for the year.

I just saw it mentioned that’s why I thought I just follow-up on it. Then finally the oil play the third oil play I think you guys mentioned, did I hear you correctly. Can you elaborate a little bit on that or..

Well we – what we’ve talked about is that it’s our strategy to add a third oil leg and we’re as committed to ever to do that. But until such time as we have definitive agreements signed there is nothing more to say at this point.

Okay. Any idea – can you give us a sense as to where it might be or really don’t want to talk about at all?

Well Paul I’ve always found it never a good idea to sort of forecast in like that. We have nothing to say at this point and as soon as we do have definitive agreements signed we will make a news release at that time.

Okay. I appreciate it. Worth just had a try. Thanks a lot.

Thank you, Paul.

Your next question comes from Timm Schneider of ISI Group. Your line is now open.

Hey good morning.

Good morning, Timm.

First a couple of questions, can you just run me through your differential assumptions in the Bakken and the Paradox and the crude oil?

Yes, Timm this is Kent. Are you talking about for 2014.

That’s right.

Yes. So and I think just a little backdrop, last year in 2013 they started really low, really got the quite high numbers in December and January, now we’re seeing them come back down. So the Bakken December and January round numbers kind of $15 and remember our differentials include our trucking costs which are about $6 or so. We’re seeing that come down by about $5 in February down to the $10 range and that sort of how we see the year probably averaging in the $10, $12 range.

Got it. So that would be $10 to $12 of your WTI forecast then just for modeling purposes?

Yes.

Okay, got it. And can you breakdown that $170 million you’re spending in the Paradox in 2014 in terms of – what does that actually mean with new wells inner ground versus science versus how much you spend in the acquisition?

Okay. So we’re going to drill between 12 to 15 wells in 2014 with the two rig program and our well costs are going to be probably in the $10 million to $11 million range as we’ve increased our lateral length, it’s increased our well cost, but of course also increases our EUR expectations. In terms of acquisition cost not prepared to share that, we are still actively pursuing other opportunities and now is not the right time to sort of talk about that.

And just so I have its current production it’s around – is it still on 3,000, this is Paradox?

Yes, in the Paradox, so if we look at quarterly numbers, third quarter was around 2,300, fourth quarter was around 2,850. Right now, we are having I will call it good days and bad days where the weather is really impacting production, but we are well above the 3,000 on good days and then a little bit below on that day, so it’s kind of fluctuating around that. But we are continuing to grow the Paradox.

Last question I had and I will get back in queue, I just want to make sure the – what’s the timing of the $200 million of equity?

Timm, this is Doran. Timing probably plan to issue that off of our ATM program that we established here a little over a year ago and so issuances would occur throughout the course of the year.

Okay, got it. Thank you.

Thank you, Tim.

(Operator Instructions) Your next question comes from Brent Thielman of Davidson. Your line is now open.

Hi, good morning everyone.

Good morning, Brent.

Just one question from me as you look at the guidance for 2014, maybe can you kind of walk us through what are some of the scenarios or particular businesses, you are thinking about that we should be considering that can kind of cause you to be at the lower end of that range?

Well, Brent, as we put out the guidance I think I’ll start off by saying I think we are positioned to have a good year in 2014. I think the range that we provided I will say is a reasonable range. Some of the things going into this you have asked about certainly timing is important from our construction businesses, how soon we can get into the field and how successful we can be at the tail end of the year. For instance last year, we had a very favorable construction season right up to Thanksgiving time and that really assisted our construction businesses. You can have the backlog there, but if you are not able to get into the field and work it and so we are able to execute on that. So we are assuming normal weather what we would expect to see from normal to get in and get out of the field particularly with construction. Pricing and production I think we have touched on that a little bit already so far as some guidance range there on the 10% to 20% oil growth. Differential something we cannot control, we put – I think some reasonable assumptions there if differentials were to narrow that would be upside to the plan. However, they were to widen extraordinarily that would be some downside to the plan as well. Weather we can’t control that certainly we have some internal diversity and kind of hedging across as we talked about for oil production December was offset by good weather that for one of the utility. So we have got average weather end of this year, last year was pretty much an average summer, but we had very cold January and February of 2013 and maybe that I will say average weather there. And as we think we are deploying capital on our lines of business that some we received the benefits that earlier, but for instance the refinery is our second year of major capital investments that Steve and his group will continue with the expectation that we are on track to have that refinery on by the end of this year. But we would not see earnings coming from that in 2014 that would actually be deferred into 2015. So and I would expect similar to last year as we go throughout the year to update you and others at the quarterly breaks or what seems appropriate when we have no information. But in summary I think it’s a reasonable range based on what we see today clearly we will update you and all as the year goes on.

That’s fair, thank you.

Okay, thanks Brent.

Your next question comes from Vedula Murti of CDP. Your line is now open.

Good morning.

Good morning.

Couple of things, one can you talk about the FERC rate case. Can you describe any – what assumption you have made for that outcome as part of our ’14 guidance?

Yes, this is Steve. As we work through that I mean obviously we are working with our customers, we will be working with the FERC staff. So we are not in a position to really speak to specifics included in our guidance range for 2014.

Okay, when the open season for the pipeline if this comes off can you remind me how large a capital program of capital item this is and when it will be in service?

Sure. Just quickly on the pipeline, it’s a 375-mile pipeline, starts kind of near well in Western North Dakota really in the heart of the Bakken, it moves North and East into Northwestern Minnesota, where we would tie into the Emerson, near the Emerson location tie into Viking, the Viking pipeline as well as Great Lakes pipeline and potentially TransCanada. Total cost of that project is $650 million. We have got a 120 day open season planned, which kicked off January 30. On following that open season, we will probably see a couple of months where we would negotiate with our customers to get final pressing agreements in place. The regulatory process would be about 2 years. So we would expect an EIS would be required for this project, which would allow for construction to start in late 2016 within the service date likely late 2017.

Okay. Would you anticipate at this point to retain 100% for yourself?

Right now, we are planning on including as part of our WBI Energy transmission pipeline and not assuming any investments from third-parties.

Okay, alright. Thank you very much.

Thank you very much.

And you have a follow-up question from Timm Schneider of ISI group. Your line is now open.

Hey, guys. Just a couple of follow-ups on the Paradox and can you just give us the average lateral length and frac stages on these new – these $10 million to $11 million well?

Yes. Tim, so our – the longest lateral we have drilled so far is around 4,700 feet and that was our 36-1 well, which is a very good well flowing about 1,200 barrels a day. The shortest lateral ironically is a 1000 foot lateral, which is our 12-1 well, which is the well that was flowing at 1,500 barrels a day, but still flowing at just under 1,000 barrels a day. So I think that’s the context. So it really depends upon where it is in the field on how long we try to drill. I think an important thing though is we do not frac these wells. We have our proprietary completion technique, but I will share with you we don’t frac them and so there is no frac stages.

And what was the reason – I think it was the Cane Creek Unit 7-1 was choked back so much, is that just for – is that infrastructure issue or is that reservoir issue, so you don’t want to damage the formation?

Yes. We are really careful on all our wells on how we bring them on production. So we are going through the same procedure that we have done for all of our wells. We bring them on slow. We choked them back. In that particular case, it’s not an infrastructure issue. When we do get up to the higher rates like over 1,000 barrels a day, then our surface facilities can be a limitation as they were for the 36-1 and we needed to make some surface adjustments there to handle the gas. It’s not about the well, but the gas. And then of course we are putting in a pipeline, which we expect to have online during third quarter to gather all the gas in the area.

What’s the gas cut on average in these wells? If you can kind of break it down oil, NGL versus gas?

Timm, right now we are not gathering any gas, so there is no NGLs. The GORs vary from as low as 400 GOR all the way up to still less than 1,000, but in the perhaps 800 range. This is very high BTU gas, once again, some variability, but in the 1,500 BTU range. So, it’s good gas to gather and we will be the first company to put our gas pipeline out in the area and we will have our processing facility and our sister company, WBI is doing all that work.

Got it. And then lastly from me, can you give us a sense in terms of what you are seeing with pressure declines in these wells after a month, after three months basically when you have to put these on pump?

Yes. Once again, there is quite a bit of variability. I mentioned to you that the 12-1 well, which came on in September, October of 2012 and it’s still flowing at 1,000 barrels a day. That’s the one extreme. We have had other wells that within 3 to 4 months we need to put them on top. And it has more to do with what part of the reservoir have we connected it to than it is pressures. There is a lot of pressure in this field. It’s a very high pressure field. It’s just due to the productivity of the reservoir that affects how quickly it goes on pump.

Alright, thanks guys.

Thanks Timm.

And you have another follow-up question from Matt Tucker of KeyBanc Capital Markets. Your line is now open.

Few follow-up questions on the refinery, can you discuss what contributed to the increase in the cost estimate? How constant are you that you have got the estimate right now and does any of that increase represent increased work for your other segments?

Sure, Matt. This is Steve. No, there isn’t any one specific thing that drove the cost increases, a number of items and I will try to give you a flavor for that. First of all, some of the site work in concrete-related activities would help drive those costs as we did our geotechnical interpretations of the soil there. We ended up having to increase the thickness of our foundations by about a third. That certainly was beneficial to our Knife River Group who did some of that work. Another area that we saw increase was environmental related things like wastewater handling systems, the processing water systems or storm water system, all those things to ensure environmental compliance just added up being more significant than we had originally expected relative to some of our pipe racks and so forth, we had to increase the height of those from our original design that helped drive the increase costs. And then lastly, I will put in the bucket of risk management type systems. This includes things like fire protection for our fireproofing of some of the facilities as well as some of our building design. So, all those things affected us, each of them kind of adding to our increase in overall costs. As I said, some of those are related or were beneficial to Knife River, but certainly not all of them. If you look at where we are at today, we are about little over 70% of the total cost of the project is either under a fixed price bid or under purchase order. So we feel pretty good about our costs. We have got over 90% of the engineering completed as we sit here are approximately 90%. So we feel pretty good where we think the costs are going to come on this. And just a reminder, we are planning to still on track to bring it online by the end of 2014 and notwithstanding the increase in cost certainly I look forward to the $70 million to $90 million EBITDA associated with our investment here and our share of that.

Thanks Steve. And then finally just on the potential announcement of a third E&P play, how likely is it that, that happens in 2014?

You guys are relentless on trying to get me to talk about something, Matt. So I will just repeat what I have said before. It’s an important part of our strategy. We are committed on doing that. And as soon as we have definitive agreement signed, we will put out a news release.

Thanks guys. That’s all I had.

Thank you, Matt.

And you have a follow-up question from Vedula Murti of CDP. Your line is now open.

Let’s see. I am wondering with the new completion techniques you are looking at in the Paradox wells if those work the way you think they will. How much room is there for acceleration in terms of development in the Paradox?

Yes. So just to clarify, the new completion techniques we are working on is for the Bakken. We have had a fairly standard completion technique that we have done over the last number of wells, probably the last year we have been fairly standard on how we are doing that. Acceleration, there is a couple of factors. One, and I will just rough start, we do look to add more rigs over time to try to accelerate our growth there. We have to be careful not to get ahead of the permits. We have to be careful not to get ahead of our learning and particularly as we are now starting to move to some different areas with the second rig as well as looking at the up-hole clastics. We could actually have a little bit of a slowdown in our production growth which will accelerate over time as we explore those new areas. So we are trying to be very disciplined here because this is an area where industry is not been able to make it work for five decades. We feel like we are on a really good track and we are trying not to get ahead of ourselves. So it will be a measured growth but as soon as we feel confident we will look to accelerate the number of rigs working there.

And my last question is that assuming that you are able to add this third well lag obviously that would then require incremental capital expenditures in ’15 and everything like that , so if we think about accelerating capital expenditures, how would you be then thinking about the possibility of an MLP as part of accessing capital?

Well, there – I think we have been quite clear on how we look at funding opportunities. And as we – last year sold non-strategic assets, that’s one thing we will look at. We will look to continue to grow our operating cash flows. We will look to debt. We will look to raising equity. An MLP is one way to look at how you might divest assets. From an E&P perspective I am not sure that would make sense. I think we might be better served as we did in 2013 to divest E&P assets to – I will call the rightful owner, it seems to – we get to maximize our value that way.

Alright, thank you very much.

Okay, thank you Vedula.

This marks the last call for questions. (Operator Instructions) This call will be available for replay beginning 1 PM Eastern Time today through 11:59 PM Eastern Time on February 18. The conference ID number for the replay is 29265471. Again the conference ID for the replay is 29265471. At this time, there are no further questions. I would now like to turn the conference back over to management for closing remarks.

Well, again thank you all for joining us on this earnings release. We are certainly pleased with our 2013 performance and continue to focus on execution of the growth opportunities that are really right in front of us. Our business units are working together to add shareholder value. And certainly we are hopeful that you might be able to attend our May - March, excuse me, March 18 Analyst Day and join us in celebrating us being in business 90 years. We are scheduled to ring the closing bell at the New York Stock Exchange that day. Again we appreciate your participation on the call and we will keep you updated as we move throughout the year. 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.