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MDU Resources Group, Inc. (NYSE:MDU)

Q4 2013 Earnings Conference Call

February 4, 2014 10:00 ET

Executives

Doran Schwartz - Vice President and Chief Financial Officer

Dave Goodin - President and Chief Executive Officer

Dave Barney - President and Chief Executive Officer, Knife River Corporation

Steve Bietz - President and Chief Executive Officer, WBI Energy

Frank Morehouse - President and Chief Executive Officer, Montana-Dakota, Great Plains Natural Gas, Cascade Natural Gas and Intermountain Gas

Jeff Thiede - President and Chief Executive Officer, MDU Construction Services Group

Kent Wells - Vice Chairman, MDU Resources and President and Chief Executive Officer, Fidelity Exploration and Production

Nathan Ring - Vice President, Controller and Chief Accounting Officer, MDU Resources

Analysts

Matt Tucker - KeyBanc Capital Markets

Chris Ellinghaus - Williams Capital

Paul Patterson - Glenrock Associates

Timm Schneider - ISI Group

Brent Thielman - Davidson

Vedula Murti - CDP Capital

Operator

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.

Doran Schwartz - Vice President and Chief Financial Officer

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?

Dave Goodin - President and Chief Executive Officer

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 only 8% revenue growth. Both our materials business and our service business had strong success. On the materials side higher margins and volumes led to an $18.5 million earnings increase compared to the prior year. The materials segment continues to see improvements across many of our markets and backlog is up $50 million from the prior year to now $456 million. We are seeing good levels of bid-letting ahead of this year’s construction season last year presenting good opportunities for expansion in our backlog position. The activity in North Dakota continues to increase and we are very pleased with nearly $100 million of work we have on the books there.

Turning to our services group, we had record earnings of $52.5 million in 2013 surpassing our peak year earnings of 2008. The results included outstanding performances by the Specialty Equipment sales and rental and our inside electrical divisions. Services backlog is now at $459 million, up 41% over a year ago. Our construction businesses have shown resiliency over the last number of years. Our focus on lowering cost structures during the economic downturn contributed to our success this last year as SG&A costs remained basically flat while earnings increased 46%. We are confident there continues to be opportunity for earnings growth at our construction group without the need for significant capital investment or material increases to our cost base. National construction indicators have remained largely positive for month-to-month driving improving markets. This along with our lower cost structure and strong backlogs have us optimistic that success will continue for our construction group as we move into 2014.

Moving on to our utility group where the addition of 21,000 customers or an increase of just slightly over 2% along with colder winter weather contributed to record earnings of $72.5 million for the year. Our electric utility business reported record earnings for 2013 that included a 6% increase in electric retail sales, largely the result of continued economic growth in the Bakken area. Our natural gas utility business reported earnings of $37.7 million compared to $29.4 million in the prior year. The increase was largely the result of colder weather in the winter months across our eight state service territory. Temperatures for the year averaged 25% colder for our Montana-Dakota group and Great Plains and 20% colder for Intermountain gas company. 2013 results saw a busy regulatory year for this group with gas rate cases approved in North Dakota, Montana, as well is in South Dakota. In aggregate the three cases will provide relief of approximately $6.7 million annually.

Additionally, the North Dakota Public Service Commission approved our request for an environmental cost recovery rider related to the $100 million upgrade at our Big Stone Station that is scheduled to be completed next year as well as we have received an advanced determination of prudency for our pollution control equipment at the Lewis & Clark Generating Station to be completed in 2016. Our utility group has substantial organic growth opportunities. We are projecting annual rate base growth of approximately 9% over the next five years and supporting that level of growth is a record five-year capital program of approximately $1.3 billion. We plan to invest $300 million of that budget this year. In addition to the Big Stone and Lewis & Clark Station environmental upgrades construction continues on our 88 megawatt, $75 million natural gas turbine to complete, to be completed in the third quarter this year that situated just across the river here in Mandan, North Dakota.

We expect to invest an additional $70 million for continued infrastructure enhancements out in the Bakken area and we continued to make significant investments in our gas distribution systems at both Cascade and Intermountain service territories to accommodate customer growth as well as routine pipeline replacement programs. Our tracker mechanism is in place for approved pipeline integrity related investments at Cascade in the year that they are made. So with a record capital forecast in place and continued strong customer growth, we are clearly excited about the future of our utility group and look forward to the rest of the year.

Now, moving on to our pipeline and energy service group, we reported adjusted earnings of $15.1 million compared to $13.3 million in the prior year. The increase was largely the result of a full year benefit from our interest in the Pronghorn natural gas and oil midstream assets. This group made substantial progress on two very large projects this year, the Dakota Prairie Refinery and the proposed 375 mile long Dakota pipeline. Construction of the Dakota Prairie Refinery is 40% complete and we achieved one of the major milestones with the arrival of our crude oil distillation tower. This is a 100 ton, 140 foot long tower that was fabricated in Taiwan, and began its journey to Dickinson, North Dakota back on November 6. After passing through the Panama Canal it departed Houston on two flatbed tandem trailers and arrived safely at the refinery site on January 21.

We have revised our refinery project cost estimate upward to $350 million with final design and engineering work now substantially complete on the project. The refinery is on schedule for completion late this year and using our base case assumptions for Bakken differentials we expect EBITDA in the range of $70 million to $90 million annually to be shared equally with our partner. And with respect to the proposed 375 mile long Dakota pipeline project, we announced just last week the commencement of an open season to obtain capacity commitments for the project. The $650 million pipeline would be the largest project in our 90-year corporate history. It would increase takeaway capacity out of the Bakken to accommodate rapidly growing natural gas production in the region. The proposed route stretches across Western North Dakota to Northwestern Minnesota and would transport natural gas to markets in Eastern North Dakota, Minnesota, Wisconsin, Michigan and other Midwest markets.

Once the 120-day open season concludes, we will evaluate the results and expect to announce plans for moving forward this summer. Construction of the pipeline could begin in 2016 with completion in 2017. This group is also moving forward on constructing a 24 mile natural gas pipeline and related processing facilities to transport Fidelity’s Paradox basin production. This project is expected to be completed by July of this year. And in addition in late October WBI Energy filed for its first rate increase since 1999 requesting an increase of $28.9 million annually. The implementation of new rates is expected to be effective May 1 of this year. Our pipeline business is in a strong position and focused on execution of the substantial growth opportunities just in front of them.

Now let’s move on to our exploration and production business. Adjusted earnings were $28 million higher in 2013, a 41% increase and the best year since 2008. Our Bakken and Paradox acreage continued to drive the group’s strong results generating an oil production record of 4.8 million net barrels produce during the year. Oil production for the Bakken increased 36% and 221% in the Paradox compared to last year. We currently have two rigs running in the Bakken with one each in Montrail and Stark Counties. We are testing alternative completion techniques in both counties utilizing more frac stages, cemented liners, higher strength propane and bearing the pumping techniques. Results to-date, have been encouraging, but there is still more work to do.

We expect to finalize completion design changes later this year and will provide more details at that time. Capital expenditures in the Bakken are expected to be about $130 million for the year as we continue our two rig program in that play. The Bakken continues to drive our E&P Group but with each passing quarter over the past year; the Paradox is taken on increasing significance for us. And we see that continuing as we move forward.

For instance in 2012, we were encouraged by early results from the Paradox Basin, but it was largely based on the success of one or two wells and production from the play accounted for only 7% of our total oil production for the year. In 2013 we repeated those early successes and production from the play represented 17% of the total oil production and in the fourth quarter the Paradox moved up to representing 21% of our oil production.

Our latest well the Cane Creek Unit 7-1 is in initial flow-back and production ramp-up period flowing on a 564th choke that’s less than one tenth of an inch in diameter. The 7-1 is producing 350 barrels of oil per day at more than 3,000 psi flowing pressure. It will be brought on to full production capability over the next month. Today we’re having a much deeper understanding of the Paradox Basin and we’re confident we have the knowledge to continue our success there. That confidence is clearly evidenced by our recent acquisition of an additional 35,000 undeveloped net leasehold acres bringing our total to approximately 130,000 acres as well as our addition of a second drilling rig to the area in December.

We’re continuing to look to expand our acreage in the field and also have an option to earn into another 20,000 acres. We’re anticipating approximately $170 million in capital expenditures in the Paradox this year. The recent acquisition in the Paradox along with the sale of $84 million of primarily non-strategic natural gas properties last year exemplify our strategy of deploying our capital dollars on oil projects with high economic returns to grow our E&P business.

We’ve also continued our focus on adding a third oil play and will announce any progress if and when agreements have been signed. Our overall capital budget for this group is approximately $440 million for this coming year. We’re projecting a 10% to 20% oil production growth along with a 5% to 10% NGL growth and a 20% to 30% decrease in natural gas production primarily the result of divestments last year. Maintaining a strong portfolio of drilling inventory is important to our E&P Group’s success. In 2013, we were pleased to replace 277% of oil production for 13.3 million barrels. Our year end reserves totaled 80.7 million barrels of oil equivalents and the 2013 PV-10 value of our reserves increased $270 million versus 2012 levels. Our E&P business had good success in 2013 and we look forward to continuing the momentum that was generated throughout the year.

MDU Resources had a very successful year. I believe it’s fair to say we executed our business plans very well. Contributing to our success was execution of our plans as to funding our projects with limited use of new equity. We accomplished this through the efficient use of operating cash flows, moderate levels of debt and the sale of certain non-strategic assets. We finished the year strong with a strong balance sheet with a debt-to-capital of less than 40%, a reaffirmed credit rating with S&P of BBB+ and our continued A- rating that we have with Fitch.

In 2014 we plan to utilize this same approach to financing our growth utilizing all financial levers available to us. Based on our current capital expenditures forecast for 2014, we plan to issue approximately $200 million of equity. Equity raise will be invested in accretive projects at our utility as it grows it’s rate base at WBI Energy as it completes and puts online at Dakota Prairie Refinery and at our E&P business it continues to grow by adding the second rig into the fast developing Paradox Basin play, where we have just added that 35,000 more acres. We are initiating our 2014 guidance at $1.45 to $1.60 per share. Our guidance assumes normal weather for the utility and construction segments as well as wider differentials for Bakken oil pricing. We have opportunities right in front of us and a record $4.4 billion five year capital budget in place. We are focused on growing MDU Resources by executing on our strategies.

Again, I would like to thank you for your time today and we will be happy to open the lines to answer any questions that you might have at this time. Operator?

Question-and-Answer Session

Operator

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

Matt Tucker - KeyBanc Capital Markets

Hi, good morning and congrats on a great year.

Dave Goodin

Good morning, Matt, thank you very much.

Matt Tucker - KeyBanc Capital Markets

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?

Kent Wells

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.

Matt Tucker - KeyBanc Capital Markets

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

Kent Wells

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.

Matt Tucker - KeyBanc Capital Markets

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?

Kent Wells

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?

Dave Barney

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.

Jeff Thiede

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.

Matt Tucker - KeyBanc Capital 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?

Dave Barney

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.

Dave Goodin

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.

Matt Tucker - KeyBanc Capital Markets

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

Dave Goodin

Okay. Thank you, Matt.

Operator

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

Chris Ellinghaus - Williams Capital

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

Doran Schwartz

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.

Chris Ellinghaus - Williams Capital

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?

Kent Wells

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

Chris Ellinghaus - Williams Capital

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?

Kent Wells

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.

Chris Ellinghaus - Williams Capital

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

Kent Wells

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.

Chris Ellinghaus - Williams Capital

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?

Steve Bietz

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.

Chris Ellinghaus - Williams Capital

Okay, great. Thanks. Thanks a lot guys.

Dave Goodin

Thank you, Chris.

Operator

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

Paul Patterson - Glenrock Associates

Good morning.

Dave Goodin

Good morning Paul.

Paul Patterson - Glenrock Associates

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?

Dave Goodin

On the realized gains, Paul?

Paul Patterson - Glenrock Associates

Yes.

Dave Goodin

Okay. Just a moment please.

Paul Patterson - Glenrock Associates

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

Doran Schwartz

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.

Paul Patterson - Glenrock Associates

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

Doran Schwartz

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

Paul Patterson - Glenrock Associates

Should we expect that in 2014 as well?

Doran Schwartz

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.

Paul Patterson - Glenrock Associates

Okay.

Kent Wells

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.

Paul Patterson - Glenrock Associates

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?

Frank Morehouse

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

Paul Patterson - Glenrock Associates

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..

Dave Goodin

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.

Paul Patterson - Glenrock Associates

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?

Dave Goodin

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.

Paul Patterson - Glenrock Associates

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

Dave Goodin

Thank you, Paul.

Operator

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

Timm Schneider - ISI Group

Hey good morning.

Dave Goodin

Good morning, Timm.

Timm Schneider - ISI Group

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

Kent Wells

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

Timm Schneider - ISI Group

That’s right.

Kent Wells

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.

Timm Schneider - ISI Group

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

Kent Wells

Yes.

Timm Schneider - ISI Group

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?

Kent Wells

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.

Timm Schneider - ISI Group

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

Kent Wells

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.

Timm Schneider - ISI Group

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?

Doran Schwartz

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.

Timm Schneider - ISI Group

Okay, got it. Thank you.

Dave Goodin

Thank you, Tim.

Operator

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

Brent Thielman - Davidson

Hi, good morning everyone.

Dave Goodin

Good morning, Brent.

Brent Thielman - Davidson

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?

Dave Goodin

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.

Brent Thielman - Davidson

That’s fair, thank you.

Dave Goodin

Okay, thanks Brent.

Operator

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

Vedula Murti - CDP Capital

Good morning.

Dave Goodin

Good morning.

Vedula Murti - CDP Capital

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?

Steve Bietz

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.

Vedula Murti - CDP Capital

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?

Steve Bietz

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.

Vedula Murti - CDP Capital

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

Steve Bietz

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

Vedula Murti - CDP Capital

Okay, alright. Thank you very much.

Dave Goodin

Thank you very much.

Operator

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

Timm Schneider - ISI group

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?

Kent Wells

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.

Timm Schneider - ISI group

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?

Kent Wells

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.

Timm Schneider - ISI group

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

Kent Wells

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.

Timm Schneider - ISI group

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?

Kent Wells

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.

Timm Schneider - ISI group

Alright, thanks guys.

Dave Goodin

Thanks Timm.

Operator

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

Matt Tucker - KeyBanc Capital Markets

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?

Steve Bietz

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.

Matt Tucker - KeyBanc Capital Markets

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?

Steve Bietz

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.

Matt Tucker - KeyBanc Capital Markets

Thanks guys. That’s all I had.

Dave Goodin

Thank you, Matt.

Operator

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

Vedula Murti - CDP Capital

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?

Dave Goodin

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.

Vedula Murti - CDP Capital

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?

Dave Goodin

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.

Vedula Murti - CDP Capital

Alright, thank you very much.

Dave Goodin

Okay, thank you Vedula.

Operator

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.

Dave Goodin - President and Chief Executive Officer

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.

Operator

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

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