Northern Oil and Gas, Inc. (NYSEMKT:NOG)
IPAA OGIS San Francisco Conference Transcript
October 2, 2013 12:45 PM ET
Michael Reger - Chief Executive Officer
Up next, we have Michael Reger, CEO of Northern Oil and Gas.
Thank you everyone for being here. Thank you IPAA for inviting us and specifically thank you for your efforts in Washington as you strengthened number one job creating industry in the U.S. Please take a moment to forward-looking or take a -- review our forward-looking statements here.
Vital statistics for Northern, our year end 2012 proved reserves were approximately 68 million barrels, about 90% of that was crude oil. Our second quarter production averaged 10,900 barrels of oil a day that was comprised of about 1,438 producing wells and at the end of the second quarter we were drilling or completing or in the process of completing another 218 wells, 17.4 net.
So if you look at the map on the right, you can see it in the blue there just shows units where we have participated in a Bakken or Three Forks well. What it really does is it highlights just where our acreage happens to be in the field and if you see the counties that encompass our acreage position you can see that our acreage is all within the core of the play.
There aren’t any big blocks of acreage that are perspective or may or may not be good. Basically we picked away these field 100 acres at a time since 2006, when we started acquiring acreage of Mountrail County for about $35 an acre. So we have been out here with a time and place advantage, and strong competitive advantage for our strategy back for the last seven years.
We have 182,400 acres. We’ve drilled approximately at the end of the second quarter 121 net wells. So we’ve got about 1,000 remaining net units, if you divide our acreage position by 1,280 acre units and then assume just a minimum of four Bakken and four Three Forks into each unit, that doesn’t take any account for the lower benches of the Three Forks or other zones.
61% of our total acreage is held by production, 71% of our acreage in North Dakota is held by production. We have a large acreage position in Richland County, Montana in an area of mutual interest with Slawson Exploration that comprised of about 25,000 acres and we’ve actively developed that over the last year and half.
We’ve drilled about three well, about 30 wells, excuse me, in that particularly play and as Slawson continues to develop Big Sky, our total acreage, held by production acreage percentage will rise quite rapidly and we expect to exit the year on our North Dakota acreage position with over 80% held by production. So we continue to develop our asset here, a steady cliff and the rig count has remained steady and our activity has remained quite high here for the last year or so.
I’m a fourth generation land man in the Williston Basin which is one of the advantages we had back in 2006 when we started leasing. We really knew what was happening on the ground in Mountrail County when EOG hit that first well in Mountrail County in May of 2006. So we have brokers on the ground basically within days of that discovery.
So we are pure-play Williston Basin operator or non-operator and participant, and we will continue to be a non-operator in the Williston Basin. We are going to continue to exploit our competitive advantage in Basin.
We are the leading non-op franchise in the Williston Basin, which makes us the first call for any seller selling non-operated interest, strategic non-operated assets in the Williston. We participate in some of the first Bakken wells in the field. We were in EOG’s fifth well in the Parshall fields. So just kind of shows how early we got in as a participant which gave us a really low cost advantage.
Our strategic non-operated acreage is all purchased really at the front end of development. So each time we acquire an acre we know who is going to drill it, when they are going to drill it, how much it is going to cost and how many barrels we are going to get. So there isn’t a big guessing game about perspective acreage and block of acreage and timing.
We have great relationships with our leading operators in the field. For years now our sort of de facto model has been we pay our money and we shut our mouth, I am not going to tell EOG how they drill their wells or Continental how to complete their wells.
We have continue to let the -- our partners innovate. We have a huge acreage position in the field. We participate in over 20% of all the wells drilled in the Bakken and Three Forks. So we are well known entity in the Williston Basin. Our partners like us. We are good partners. Again, we pay our bills and we keep our mouth shut. So they really like us.
Again, we develop our acreage and acquire our acreage right in the development, on the verge of development. So Northern typically is going to acquire an acre that easily subject to a well proposal or an ASE when we actually acquire it.
So we have -- we might get a call from somebody saying they have got approximately 120 acres under lease. This might be a broker in this market, might be a, it might be another operator was non-operated interest in another operators well and they will give us call saying they just receive the well proposal on this asset, that’s about 10% of 1,280 acre unit. Maybe for budgetary reason, typically its for budget reasons why don’t participate in that well. We will acquire that acreage and immediately participate in the well.
So it’s a very fast turn -- return of our capital. We don’t buy acreage hoping some day it will be developed. It’s typically fairly defined within the next quarter or two when the well will not only be up spud but probably even producing.
Again we’re partnered with leading operators. We participate with over 25 operators in the Bakken play. Shortly here I’m going to show you a pie chart that just shows the diversification of our operators by percentage of net wells that we participated in since 2006. That will just give an idea of how this all breaks down.
We get to chose to participate with the best operators based on the acreage that we’re acquiring. Somebody shows that 100 acres or couple of 100 acres in a unit, we don’t particularly care for that location or that area or that particular operator. We can choose not to acquire that. We can stay focused and strategically deploy our capital into the areas and with the operators that we really do like to participate with.
Again we have an extensive multiyear drilling inventory. If you take the thousand net remaining locations, figure we’re going to drill somewhere between 40 and 50 net wells a year, we’ve got about 22 to 25 years of inventory left if we drill 40 to 50 net wells a year.
So we’ve been drilling 40 to 50 net wells a year for the last three years. So just based on the inventory in four wells at Bakken and four wells at Three Forks, we’re going to be out here for several decades.
We have the ability to continue to acquire non-operated strategic acreage. Northern’s balance sheet is really the key. Five years ago was really our relationship with the brokers and land folks in the field but today we’re starting to see more packages where we can come in, buy a block of acreage and buying the acreage really isn’t the financial burden. It’s the continued CapEx that comes from infill drilling and pad drilling.
We recently acquired about 2,000 acres from an operator in another operator’s unit. And we paid about $2,500 an acre that was about $5 million. The issue wasn’t $5 million. It’s just we’re going to be also faced with about $125 million drilling CapEx over the next five years if that operator develops it.
So that’s like Northern is really able to stand alone in the field as the only bidder for these large actively drilled non-operated position. So we really do have a competitive advantage and a strategic niche in the field, mainly now just because of the size of our balance sheet, it gives us the opportunity to pick up these yields as we go.
Again, the play is multi-pay and stacked pay. We’ve got the Bakken, the Three Forks and the three lower benches of the Three Forks. So we have basically surfaced the core on all of our leases. So as new plays, we see -- started to see some Red River activity with Whiting and others. That would be -- that would fall within our leases obviously as well. So we’re excited to see the technology curve continue to expand.
So few graphs to show Northern’s growth over the last three years, on the top left is our revenue. You can see trailing 12 months as of the end of the second quarter was about 320 -- $330 million. Adjusted EBITDA trailing 12 months was about $250 million. Proved reserve at the end of the year was $67 million and total book capitalization at the end of the 2012 was over $1 billion. So we continue to grow. Those were just some highlights of our activity for last five or so years continuing up into the right.
These are breakdown of our reserve position. One thing I really just want to point out on this slide is we had a -- we have a PV10 at the end of the year. We had a PV10 of just under $1.3 billion.
And what’s important to note about that is that our reserve base only has about two years of scheduled PUD. We work with Ryder Scott in Denver and because we’re non-operator, Ryder Scott and Northern have basically chosen to schedule about two years of PUD as oppose to the SEC allotted five years of PUD. Because we’re non-operator, we can specifically tell them which wells are going to be drilled in years, three to five.
So $1.3 billion of PV10 only has two years of scheduled PUD drilling out of -- if you look at our vastly held by production acreage position, we’ve got about a minimum of 22 years of drilling. So our PV10 of $1.3 million -- $1.3 billion excludes about 20 years of drilling inventory. So just from our -- from a PUD drilling inventory standpoint, it’s very limited when you see our actuals year end PV10 and year end proved developed.
So again 90% crude oil. This is not new to anybody who follows the Bakken. And it’s just a very highly economic play as you know. This is the breakdown of our acreage position. You can see that about 80% of our acreage is in North Dakota and the balance is in Montana predominantly in the Slawson, Big Sky area of mutual interest that we’re developing with them.
We have about 31,000 acres in Richland County but some of that is north of the Elm Coulee field that we’re developing pretty actively with XTO and most of the continental. So a majority of our acreage in Richland county is in the Big Sky AMI with Slawson. As you can see that continues to develop are held by over -- are held by production, percentage will increase fairly rapidly. But if you look over in the left, you can see the breakdown of our acreage in North Dakota.
You see, we have, most of our acreage in Mountrail county, that’s where we got our start, that’s where we had our low cost advantage and that’s where we were able to really build our substantial reserve in production base early and at a low cost, which has allowed us to sort of grill and build such a sound liquidity cushion.
But you can see the top five county, they are Mountrail, Dunn, McKenzie, Williams and Divide. That’s really the bulk of our acreage position and then as I showed you on the map, if you remember the blue and yellow map, you can see it’s all strategically located right in the delineated core of the field.
So there is no big block of 50,000 out there that may or may not be good. Our entire acreage position was thought strategically, basically at 100 acres at a time except for the area of mutual interest and the acreage that we acquired with Slawson and the Big Sky play in Richland County.
Again Northern is acquiring our acreage. We are acquiring our acreage one step ahead of the drill bit. We have so much data in the field, but now if you take the wells that are currently drilling at the second quarter plus the wells that we drilled. And then we also pre-announced July, where we had completed 61 gross -- excuse me -- 62 gross, 6.4 net wells which in July was more net wells completed in all of the second quarter combined, mainly because weather improved.
You add those to the total we participated in over 1700 wells in North Dakota. We have so much data on what areas are good, what operators are working with, what their costs are, what their profit type is, what their completion design is. We have great visibility on who they are, what they are doing, how fast they are going to drill. We’re always talking to our operators about their rig counts and their cost and where their cost are trending, where actuals will be as they relate to AFE estimate.
Most of our acreage as I mentioned earlier is acquired in already permitted locations. I really can’t remember the last time we bought a bunch of acreage where we didn’t really have the permits or lease acreage that was on the dockets of the North Dakota Industrial Commission for permit.
Again, we also purchase our acreage at a discount to the way you are seeing in the market from these operated packages that you are seeing. But we start to see the consolidation happen in the field. You have -- our acreage is typically picked up in that $1,000 to $2,000 an acre range. If you were to acquire a 1,280 acre unit, that was 100% -- where you owned 100% of acreage or the lease hold interest in that particular unit, you’d have all the operators in the field competing for that acreage.
And really if you have 100 acres in a particular unit, it’s really only Northern that’s competing for that strategic non-operated asset. So we have very little competition which means that we’re always going to be purchasing at a discount to the operated market or the big transactions that we’re starting to see.
Our deal flow is really coming from three places. Lot of land man and brokers and friends of ours in North Dakota and Montana who are divesting acreage they’ve required. Non-operated acreage, we acquire -- majority of our acreage now is acquired from operators divesting non-operated interest to us that are in other operators well.
And then also we’ve participated in quite a few deals over the years. We kind of coin them as buy down where operators for different budgetary reasons might ask us to buy them down in a particular unit.
We did one particular deal where an operator had about 75% working interest in six drilling spacing unit in one particular area. And they ask us to buy them down to 50% interest in unit because they wanted three net wells with exposure as they drilled those six units, so they could hold those units by production.
So we call that a buy down and that particular operator sold us 25% working interest in each of those units. They drilled all those wells back to back and we bought -- I think we paid $1750 an acre. This is about a year and half ago. And those acres, those units are all drilled and the infill drilling is currently going on right now with one rig in those six units.
So we’ve done a lot of deals like that. We’ve done a few with Slawson and Northern Mountrail. It’s usually just a budget issue where we’re buying these operators down to a comfortable budgetary requirement for them.
Our acquisition track record, you can see that our average acquisition price in 2012 is about $1800 an acre and in the second quarter 2013 it’s about a $1,000, little over $1,000 an acre, lot of that was because we were adding to our acreage position with Slawson in the Big Sky field.
We have been buying acreage at substantially below $1,000 an acre. That brought our average down. But our typical average is going to be somewhere in the really now probably the $1,500 to $2,500 acre range for a typical North Dakota and non-operated acreage position.
We handpick all of these leases as we go. I mentioned early we’ve grown our position. Our total position from 3% in 2008 to 61% held by production in the second quarter of 2013, again 71% in North Dakota, about $20 million this year is allocated to acreage acquisition. So which represents, you will see in a slide here, in a few slides will, that will be less than 5% of our total CapEx this year.
So here is what really get to the need of the presentation, now that I have shared with you a little bit about our strategy. This is a breakdown of our operators here. You can see that between EOG have Continental and Slawson makes up 50% of our total net wells drilled to date.
And what’s important to note about that is, that isn’t because we are -- we really pick those particular operators. It is just because those particular operators have such a dominant position in North Dakota and we, excuse me, Montreal County, North Dakota. So that’s where we really started building our acreage position as we have done along here.
So, you can see the breakdown, it’s mainly EOG has Continental and Slawson make up over 50% of our position or net well and that will probably be fairly static as we go forward as we’ve started -- as we start to employ these units.
Here is the breakdown of the top 12 operators that we work with. You can see the amount of rigs that they are operating in the Williston and the amount of CapEx. See in the left, there you are going to see, these operators are going to spent over $10 billion drilling in 2013 alone, which is a staggering amount of CapEx and Northern captures the innovation and the technology, the free technology call option that comes with these operators spending this amount of time and energy on this particular play.
I think the buzz of this conference has been the new completion design by EOG where they are tripling, in some cases quadrupling, the amount of sand they are putting into these wells, which really is improving the EURs that we are seeing.
So as we continue to basically see the step changes in EURs and completion design, these partners and this kind of CapEx, Northern the direct beneficiary of this and one interesting tip there on the bottom right here, 80% of the rigs that we’re running in North Dakota as of the end of second quarter, we’re running in townships where Northern Oil controls lease hold interest. So you see how tightly held we are to the activity from these 12 operators.
I will skip this slide, but one thing I just want to point out at the top, as you can see that the rig count has stabilized in the Williston and production has continue to increase, which just shows the efficiency of the play.
This is a log of the lower benches of the Three Forks. We have working interest in the Continental Charlotte unit. That was their first big lower bench test where they drilled off three, all three of the lower benches of the Three Forks which was very exciting for us to participate in. We got to see that real time.
This is one important slide about capital efficiency. We generated $3.50 in EBITDA for each dollar deployed F&D. So that’s as you can see compared to our, all of our peers in the field, you can see the efficiency there.
Acquisition development budget, I show this kind of on the bottom, there you can see that $20 million less than 5% of our total CapEx is going to be spent on acreage this year the rest just on development. On the bottom right there shows it as a percentage. So we are really shifting to development.
We just increased our borrowing base yesterday from $400 million to $450 million. As you know that was undrawn at the end of the second quarter. But if you take the $18 million we had in cash at the end of the second quarter, a $450 million borrowing base, $249 in trailing 12 month EBITDA and then if you skip over to the far right, we have $372 million of CapEx this year. We were $345 million liquidity cushion for 2013 alone as we start to even forward into 2014 and ‘15 as we get the cash flow neutral and cash flow positive.
So, it’s really an testament to the reserve base that we have built over the last seven years and the production reserve capacity we have. They are really on top of our reserves we have a lot of production cash flow here to expand our liquidity position.
We have a very strong hedge book here. I just want to point out specifically in 2013, a majority of our swaps in the remaining quarters of 2013 were 90, excuse me, the remaining -- the majority of our hedges in 2013 were 91 of our callers. We were able to capture a lot of this 100 plus oil in the third quarter. So it has been really exciting for us.
And again, we are basically hedged out pretty well through 2015 at about $90 a barrel, because we don’t believe that we are hedging to get the best price, we believing we are hedging to protect our liquidity position as we continue to develop this field.
This slide, I will just note that we have identical cash operating margins to our other pure-play peers Oasis and Kodiak. So as you can imagine, we have the same wells exactly the same cash operating margins. And then if you then carry forward here, you can see that Northern just gets cheaper as we go here.
Same cash operating margin, a three-year F&D is lower than some of our other peers in the basin. And then most important slide here, is enterprise value of the proved reserves were almost the cheapest in the whole play and then enterprise value to production, you can see how cheap we are relative to our pure-plays Kodiak and Oasis and Continental.
Final slide, I have covered all this, but it’s a proven acquisition model, we have been very discipline about how we acquire this acreage. We are not going to become an operator. We are not going to another basin. We are going to continue to pick away this field, 100 acres at a time. We have been doing it for seven years in a very discipline manner. We continue to grow our asset base, continue to grow our reserves and our liquidity position.
Well, it go to non-buyer in the field. We now stand alone as the only non-op in the field of record. We are partnered with the best operators and the best resource play in the country. We have got great growth potential ahead of us.
Looking forward, very much looking forward to sharing our third quarter results in early November as the field really started to behave once weather got better in July. So thank you all for your time. Thanks for being here and thank you again IPAA for your efforts.
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