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Enerplus Corporation (NYSE:ERF)

Q2 2012 Earnings Call

August 10, 2012, 11:00 am ET

Executives

Jo-Anne Caza - VP, Corporate & Investor Relations

Gordon Kerr - President & CEO

Ian Dundas - EVP & COO

Rob Waters - SVP & CFO

Eric Le Dain - SVP, Strategic Planning, Reserves & Marketing

Analysts

Greg Pardy - RBC Capital Markets

Robert Bellinski - Morningstar

Roger Serin - TD Securities

Gordon Tait - BMO Capital Markets

Bruce Robinson - Equity Pacific

Jason Frew - Credit Suisse

Operator

Good morning. My name is Michelle and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus Corporation 2012 second quarter results 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 session. (Operator Instructions)

I would now like to turn the call over to Ms. Jo-Anne Caza, Vice President, Corporate and Investor Relations. Please go ahead.

Jo-Anne Caza

Thank you, operator, and good morning everyone. I would like to welcome you to our second quarter conference call. Gordon Kerr, our President and CEO will be summarizing the results of the quarter this morning and Ian Dundas, our Executive Vice President and Chief Operating Officer will provide an update on our operational result. To help answer some of the questions at the end of the call, we also have with us Mr. Rob Waters our Senior Vice President and Chief Financial Officer; Mr. Ray Daniels, our Senior Vice President of Operation; Mr. Eric Le Dain, our Senior Vice President of Strategic Planning, Reserves and Marketing and Mr. Rod Gray, our Vice President of Finance.

Before we get started, please note that this call will contain forward-looking information. Listeners should understand the risks and limitations of this type of information and review our advisory on forward-looking information at the end of our news release issued this morning and included within our MD&A and financial statement filed on SEDAR and EDGAR and also available on our website at enerplus.com. Our financial statements were also prepared in accordance with International Financial Reporting Standards [IFRS].

All financial figures referenced during this call are in Canadian dollars unless otherwise specified and all conversions of natural gas to barrels of oil equivalent are done on a six to one energy equivalent conversion ratio which does not necessarily represent the current value equivalent. Following our review, we’ll open up the phone lines and answer questions you may have and we will also have a replay of this call available later today on our website.

With that, it’s over to you Gordon.

Gordon Kerr

Well, thanks Jo-Anne and good morning everyone and thanks for joining us on the call today. I want to give you a brief overview of our financial and operating results and then I am going to it over to Ian who will provide more detail on our operations before we open up for questions.

Starting-off, Q2 marked another quarter of production growth through the drill bit for Enerplus. Our daily production averaged to 82,100 BOE per day and it's 4% higher than the first quarter and 9% higher year-over-year.

Notably our oil volumes increased by 7% quarter-over-quarter as a result of our successful drilling at Fort Berthold and in our waterflood properties. Accrued oil and liquids volumes now account for 49% of our total production helping support our funds flow through a period of weak gas prices.

We spent a total of CAD$209 million on capital expenditures during the quarter; 80% of which was focused on our oil assets. The majority of spending continued to be on tight oil play in the Williston Basin area of North Dakota. And we continue to have an active operated program in this area.

We've also seen a substantial increase in activity by our non-operated partners in this region. In addition, we have increased spending on infrastructure related to pipeline connecting our wells both to capture associated gas production and reduce the hauling of oil. Spending on our natural gas assets has been limited with the majority of activity occurring on our non-operated properties in the Marcellus in Northeastern Pennsylvania.

Operating cost were on-track with our forecast for the quarter of CAD$10.78 per BOE and G&A expenses were CAD$$2.81 per BOE including both cash and equity based compensation. Our funds flow during the quarter was CAD$$147 million, down 10% versus Q1 but ahead of analyst consensus of CAD$$131 million.

Higher oil production volumes during the quarter provided the additional support to our cash flows. We took three important steps during the quarter to manage our balance sheet. First, we issued C CAD$405 million of long term senior unsecured notes at approximately 4.4% coupon rate and the proceeds of this issue were used to reduce the borrowing under our bank credit facility.

Secondly, we implemented the stock dividend program which gives all of our shareholders the choice to receive their dividends as shares in Enerplus instead of cash. This replaces our DRIP, which was available only to Canadian shareholders.

As a result of opening the [STP] up to our entire shareholder base, we have seen early participation of about 17% of total dividends paid. This compares to around 11% for the first five months of 2012 under the old DRIP.

Thirdly, we reduced our monthly dividend from CAD$0.18 per share to CAD$0.09 per share.

As a result of these measures and our activity in the quarter, our debt for the 12-month trailing funds flow was two times and 68% of our CAD$1 billion line of credit was available to us at the end of the quarter. We also continue to increase our hedge positions for better funds flow.

We have 18,500 barrels per day of oil or 63% of our 2012 net oil production hedged for the remainder of 2012 with approximately CAD$96 per barrel of WTI and now have 14,500 barrels per day for 2013 net volumes hedged at over CAD$101 per barrel of WTI.

With the recent improvement in natural gas prices, we have put in place for protection on 23 million cubic feet per day of natural gas in 2013 at a price of CAD$3.17 per Mcf (inaudible). We will continue to look for opportunities to add to these hedge positions under our hedging strategy as we move forward. And now I will turn the call over to Ian to give you more details on our operations during the quarter.

Ian Dundas

Good morning. Our focus this year has been on executing our capital spending program to deliver on our growth targets as Gordon said and this is another quarter of strong organic production growth for us. So let’s start in North Dakota. Overall, we are pleased with field performance. Production is growing. We are beginning to make progress relative to our cost objectives and projected economics remain strong.

We spent almost CAD$140 million here during the quarter. We drilled seven net wells and brought eight net wells to production; year to-date, we have drilled 16 net horizontal wells and brought a total 11 net wells onstream.

Our primary focus continues to belong in Bakken wells, but we have brought forth Three Forks well onstream as we continue to delineate that resource. Production averaged 11,700 barrels of equivalent a day, which is nearly a 35% increase from first quarter and a bit ahead of where we had planned to be at this time of the year; obviously, cost control continues to be key focus area.

As you may recall, we had targeted at the beginning of the year to reduce our D&C cost over the course of the year for long lateral worth CAD$10 million. The completion would represent two-thirds of that total cost.

Although, costs have stabilized in the second quarter and we made some significant progress in certain areas we have not yet achieved that goal. Year to-date our D&C costs have averaged approximately CAD$12 million for long wells, which are typically 9,000 foot laterals, 23 to 25 stages and we continue to use high strength [ceramic process]. To improve cost performance on the drilling side we have dropped our two least efficient drilling rigs and plan to run with two operator rigs to finish our program this year.

Performance on our remaining rigs has been significantly better and we would anticipate this action alone will bring our average drilling days down by 15% to 20% compared to the performance we have been experiencing on average. Current drilling cost for our remaining rigs are in the CAD$4.5 million dollar range which will lower our drilling cost by more than a CAD$0.5 million dollars per well on average.

We are also continuing to focus on optimizing our completion costs. We recently tested the use of the frac stages in West Province; although, we have seen lower costs, additional run time is needed to determine whether recoveries will be similar to our previous completion techniques.

Looking forward a key area of cost saving will be achieved as we move to more pad based drilling. We would expect that this approach could save 5% to 10% per well. As most of our wells have been drilled on single or two well pads this year we will not see a large benefit of multi well pad drilling in 2012.

However, subsequent to the quarter we did complete four well pad and achieved D&C costs at approximately CAD$11 million per well. Our final cost and cost in the basin, at the macro-level we have seen cost stabilize but not necessarily fall in any meaningful way.

As we look at activity levels currently and look forward to the course of the year and the overall state of the supply chain, we expect that we may see some relief particularly for drilling and pressure pumping as we move towards the backend of the year and into 2013.

Although, we continue to target cost reductions below the CAD$12 million level, the economics of our program at Fort Berthold continue to offset at current cost using CAD$12 million well cost and based on the current forward strip rate return on our Bakken wells is approximately 50% with (inaudible) at CAD$11.5 million and a recycle of our three times. Even though we operate approximately 90% of our leasehold, we did see a significant increase in the level of the non-operated spending over our original expectations.

Initially, we are expecting a modest level of non-operated spending, given the limited amount of non-operated acreage. However, year to-date we have spent approximately CAD$35 million on non-operated activity and expect the spending will continue at similar levels over the remainder of the year which has contributed to an increase in spending in this area. To frame the onstreams initially we were expecting somewhere in the range of one net onstream this year and looking forward, we think that's going to be in the four to potentially five net wells.

Finally, we have seen some increase in the scope of our infrastructure build-out as we move to ensure we are gathering all of our associated gas in a timely fashion as well as recovering associated liquids. We are currently looking at potential fee based arrangements for this capital linked to the third party gathering arrangements we already have in place.

Currently we now have two-thirds of our wells tied in. The total amount of this spend we would anticipate somewhere in the CAD$25 million range this year. If we do not execute on the sort of, if we do not execute on these additional third party arrangements.

Turning to our oil waterflood properties, production was up approximately 5% in the second quarter as a result of our drilling and optimization efforts. We continue to drill through break of the Med Hat Glauc C in preparation for our [EOR] project. We also recommenced our Southeast Wisconsin drilling program after break up at Freda Lake in the Ratcliffe trend. We continued our positive results in this area with our most recent well coming well above expectations, producing 324 barrels of equivalent a day during its first week.

At Giltedge, we continued to advance on Med Hat Glauc C injection project. Overall, project is generally on track however timing of P production is somewhat behind as we have works to optimize our injection rates. We have been experiencing some equipment capacity constraints that did impact polymer injection rates. We believe we now have engineered a new solution with a retrofit to the polymer slicing unit which should allow us to reach desired injection rates in the next month or so.

Despite the operational issues we've seen encouraging incremental production gains of approximately 200 barrels a day in the pilot area. We will be able to evaluate the performance of this pilot and determine our go forward plans ones we are injecting this plan and we see a good response.

Moving to gas, our Canadian gas volumes continued to decline as expected as we are not investing in our shallow and conventional natural gas assets. And our deep gas play production did increase by 2% from the first quarter to average just over 87 million cubic feet a day in the quarter driven primarily by our success in the Wilrich in the Ansell area. In the Marcellus, our capital spending continues to be driven by our non-operative partners in Northeast Pennsylvania as they focus largely on acreage retention.

Rig channels have dropped from early in the year and we're seeing a slowdown in the pace of tie-in activity. Some of our partners are also partially completing or toe fracking wells in order to manage capital and still lease obligations. We now have total of 24 net non-operated wells that waiting for full completion or the tie-in this region.

Production is growing as we produced and average 37 million cubic feet of gas a day during the second quarter. However, we're tampering our expectations for exit from the Marcellus to 16 million cubic feet a day down from our original expectation at 70 million in a day. Although, well performance remains strong, we expect a pace of nonoperated completion activity to slow somewhat in response to the current gas price environment.

Overall we would expect activity level across our entire operations moderate in the second half of the year and we're closely monitoring our spending levels. In summary, I am quite encouraged by operations. We’re seeing strong oil growth out of Fort Berthold. We are continuing to extract value at our oil waterfloods producing very good results in our deep gas assets in Ansell and are maintaining the opportunities in a non-operated Marcellus acreage. With that I'll turn the call back to Gordon.

Gordon Kerr

Okay, thanks Ian. Looking at our guidance for the remainder of the year and due to the increased spending at Fort Berthold, we’re increasing our capital spending guidance to 850 million versus our original estimate of 800 million. We are also increasing our annual production guidance from 83,000 BOE a day to (inaudible). Recognizing the incremental production associated with the non-operated spending of Fort Berthold.

Our exit production guidance was stay at 88,000 BOE per day as we expect to slowdown in completion and tie-ins in the Marcellus gas play may impact production volumes for the latter half of the year as Ian referenced.

On the cost side, on the cost side we are on track to meet our operating cost guidance of 10.40 per BOE and we are reducing our G&A guidance to 330 per BOE from 355 per BOE due to lower costs associated with our long-term incentive programs.

I want to wrap up my comments with an update on our funding initiatives we discussed earlier this year. As many of you will know, we have significant potential development opportunity in front of us in the Duvernay, Montney and sets operated in Marcellus plays. We said back in April, we would look to bring in partners to help develop these assets or potentially sell down a portion of them. We formally kicked up the process with our financial advisor in July and now are actively marketing these assets focusing mainly on the Duvernay and the Montney assets due to the interest in these areas.

We are also continuing with our plan to monetize our equity portfolio, and we have now expanded our plans to include possible sale of other non-core producing assets to help retain our financial flexibility through 2012 and into 2013. To conclude, we are continuing with our execution on our capital spending plans with the majority of the spent focused on our well projects, working to advance our early stage resource place and progressing on our funding initiatives.

With that I will turn the call back over to the operator and we will take questions.

Question-and-Answer Session

Operator

[Operator Instructions] our first question comes from Greg Pardy from RBC Capital Markets. Your line is open.

Greg Pardy - RBC Capital Markets

(inaudible) with four quick ones, just curious so as to what are you thinking of cash taxes will shake out for 2012, second the 25 million of third party capital in the Bakken just wondering if that’s already embedded in the revised CapEx of 850 or whether that possibly would be an addition to and just interested about what you are seeing from an IP raise standpoint in the Bakken and then the last thing just Ian’s comment around the 24 net wells in the Marcellus yet to connect just curious what the gross well count might be that would be a test to that. Thanks.

Ian Dundas

(inaudible) so I can have triple questions asked, the $35 million of spend associated with the non-op that’s that's built into the (inaudible) IP rates on both verticals I think you said and then COG with regard to 24 net wells. So let Rob Waters, our CFO address the cash tax question.

Rob Waters

Hi, Greg, our guidance on cash taxes hasn't changed, so what we've been saying and we still adhere it in the context of today's current commodity price environment we don't expect any material cash taxes in Canada until after 2015 and that's because we have sufficient tax book coverage. In the US we expect cash taxes at a rate that is approximately 5% of our net cash flow in the US and again that number is low because of tax coverage there and of the tax we are paying most of it is what they call alternative minimum tax that we can recover in the future taxes.

So I think today we paid if you look at the first half of the year about $4.5 million in cash taxes as a company, most of that was in the US and then if you do the math on the US cash flow it turns out to about 3% you know of US cash flow so whether its 3% to 5% is a bit of our rounding so we are kind of on track with guidance there. Extrapolating for a full year and again it depends what oil price you are using in your model, you can expect cash taxes in the range of about $10 million to extrapolating what we've seen in the first half of the year.

I would note that if you look at last year there was about $44 million of cash taxes but I will remind you that we sold some Marcellus assets and there was tax associated with the big gain on that sale so last year isn't a very good proxy for what's happening this year.

With respect to the $35 million with regard to the, $45 million sorry, yeah, $10 million operating, it is build into the 850 BRIC and I'll let Ian answer the questions on the IP rates and the 24 net wells he referenced.

Ian Dundas

Hey Greg, I'll start with the third question, the net to gross well count in the Marcellus, I don't have that exact number for you but we can get it for you. But I would say we've got largely three operators there with various working interests, and 150 net wells. There's a lot of 25% to 30% stuff but we are drilling some wells in Chesapeake at very low working interest that are quite tactical. So I'll come back to on that number but it's close to that level. Okay so IP view our performance, so lets talk reserves we have a type well for a long Bakken well completed with ceramic based on two wells per 1280 spacing units of 800,000 barrels and then a gas and liquids on top of that and that we are tracking to that level still so let's, we still anticipate looking at the end of the year.

The IP answer is a little more complicated. Our type 30 IP is 1,100 barrels a day again for that same well. That would assume effectively unrestricted flow incompletion in unrestricted flow which was 30 days and we have been tracking that level of late though we are testing whether we should potentially restricting flow a little bit there talking about those wells, its (inaudible) we might intense long-term performance to potentially improve cost structures. So enhanced economics and although IP 30 a little bit lower IP 90 about the same we would think. So I guess I am not dating those numbers yet since we’re in the process of working away through that right now but if decide that’s a better approach , you will probably see a little bit of downward pressure on the IP 30 and real similar economics.

Greg Pardy - RBC Capital Markets

Okay, and the 1,100 BOE a day is that a BOE or is that oil number?

Ian Dundas

Okay (inaudible) Bakken I guess we don’t have enough data points to large enough samples set to state definitively what the Three Forks look like. We’ve been running Three Forks at about 70% of rate reserves relative to those Bakken wells. I would say we are tracking that. We have some wells it actually look like a good Bakken well, some of them are under that but it is still a little bit early to something other than that 70% number.

Operator

(Operator Instructions) Your next question comes from the Robert Bellinski from Morningstar. Your line is open.

Robert Bellinski - Morningstar

Good morning. The release mentions managing spending to offset the increase in the Bakken I was just wondering, could you drill down a bit as to where you are pulling back?

Gordon Kerr

Yeah, I think by large its in Canadian operations because we continue to focus our spend within again Fort Berthold region. So Ian going to add further color to that. Yeah that's be large fleet. Initially in the year, we would have talked about four rigs, operating rigs going to 3 rigs. In North Dakota, now that's four going to two, you know, although a little bit of net well count look about that same. Those are the two big moving pieces for us and the Canadian operations I would say I guess two things, a little bit less gas spend than we had forecasted at the beginning of the year although there wasn’t a tremendous amount and then a reallocation of some of our Canadian tight oil to U.S. tight oil.

Robert Bellinski - Morningstar

And then my second question is just wanted to give us an idea as to what employee turnover is looking like at this point.

Gordon Kerr

I guess on the aggregate sense and we can follow what are the trends in the industry in that and it’s not dissimilar to what we are seeing in others out there in the industry. I mean turnover rates I think in the last few years generally across the industry have been in the order of about 12% on an annualized basis. So there is still a lot of competition for steel sets in our industry, but I think we are seeing some stabilization in that area too.

Operator

(Operator Instructions) The next question comes from Roger Serin from TD Securities. Your line is open.

Roger Serin - TD Securities

So three questions, when you say exit rate, are you thinking December 31?

Gordon Kerr

We are really thinking December. We can’t predict that actually.

Roger Serin - TD Securities

Well that’s not a Q4 I guess is what I was obviously trying to confirm. It will be what you need to make the exit, how is that?

Gordon Kerr

Those are your words.

Roger Serin - TD Securities

Okay, so next question when I think about pricing of the Marcellus gas volumes there has been some obviously some discounting to NYMEX depending on if you have takeaway capacity. Your numbers have not moved around a little bit, but you have got the two things going in the transportation and then the BTU adjustment.

Could you give us some color on how we should think about pricing of your Marcellus gas?

Eric Le Dain

We're benefiting a bit from our connections into the Transco system as opposed to being focused on Tennessee Interstate Pipeline for takeaway and we're probably in zero basis differential to minus five type range and we see that continuing.

Roger Serin - TD Securities

To NYMEX?

Eric Le Dain

Versus NYMEX, yeah.

Roger Serin - TD Securities

DRIP, so in this quarter when you changed your program, it looks to us like your DRIP participation dropped in half. Do you think that will pick up as people get familiar and may be some of your US shareholders participate or has there been some of the institutional holders that can't participate? Give me some guidance on where you think DRIP goes or your revised program.

Gordon Kerr

I think we commented Roger that we see our participation rate has actually increased certainly with the reduction in dividend and then the absolute flow of funds back in. But I think as more of the information gets out in terms of the ability to participate in the program, we anticipate that we will see that maybe increase some more or so.

Rob Waters

And keep in mind that we cut our dividend in half too, Roger, so yeah.

Roger Serin - TD Securities

Last question I think. Can you give us some timelines on I'll call your monetizing strategy of your early stage assets or equity assets? You've engaged an advisor. Can we expect to hear something by Q4? When are bids due? How formal is the process that kind of thing?

Gordon Kerr

Well, the process as I indicated has been commenced, we take this up in July. We haven't set a firm bid date. Right now we are in the process of engaging parties in terms of execution on (inaudible) as well as having had all materials prepared and ready perhaps and so we are really on that.

I expect as we move through the course of the year and towards the back end, we will have further clarification on where we stand on the initial count. But we are right to say right now we are encouraged by what we are seeing and that's why as I said we've put the focus on the Duvernay and Montney and where we really see we really some good interest.

Operator

Next question comes from Gordon Tait from BMO Capital Markets.

Gordon Tait - BMO Capital Markets

Maybe just a little bit more on the Marcellus, you said from spending commitments in the Marcellus, there's been a little bit of an uptick in the gas market this summer. How do you think about hedging in terms of what your spending commitments are and what you need to see to sort of meet those obligations?

Gordon Kerr

Well, I don't know that we would actually connect so directly with what's happening in the Marcellus in isolation. Certainly a significant part of our gas production is still based within Western Canada. So as I said earlier we've put some good protection in place on a 3 million cubic feet a day of our gas production for 2013 and so we've retained all the upside.

So we are still I would say somewhat on the bullish side in terms of and in relative terms these days, but in terms of where the gas prices can go. So we will continue to walk through opportunities to maybe shore up some additional footprint production and you know if we see improvement in price up to a point where we want to swap, we would not be averse to maybe swapping some of our gas as well.

Rob Waters

And Gordon our Marcellus security commitment is now down to $4.6 million. So the carry obligation in the Marcellus is down to a pretty nominal amount now.

Gordon Kerr

And I would suggest by this point now at the end of the second quarter, it's sure is done.

Ian Dundas

Gordon, I'll just add one more comment too. These are big ships that take a little while to turn these companies. Our partners in particular and notwithstanding, we've seen a bit recovery. We're not anticipating a rapid turnaround in that drilling this year. It will take a bit of time.

Commitments are being talked as we speak and I think they will pick up the tone and we see I would say more risk to the downside in terms of the activity this year than upside. It will turn next year potentially, if we see continued strength but –

Gordon Kerr

And I think Gordon that downturn and activity speaks to the opposite of the equation on the price side in terms of what might help support better gas prices.

Operator

Your next question comes from the Bruce Robinson from Equity Pacific. Your line is now open.

Bruce Robinson - Equity Pacific

Good morning and I wanted to say that your progress on the production side is very comforting. But I'd like to if I may ask you take sort of a broader rush or step back and look at something that's a little more on the macro side.

In terms of the transformation of the organization, that's gone on over the last three or four years, how would you characterize -- first of all how you perceived your unit holders or now your shareholders as being income oriented as opposed to people that would typically invest in an exploration and production company.

The second side of that is when you look out to 2013, 2014, 2015, do you have as an active objective increasing your dividend again or simply trying to stabilize the dividend over time with the current levels?

Gordon Kerr

As we have transitioned the asset base to try to find the right balance between bringing growth into the portfolio and at the same time sustain committed to dividend as part of the value proposition for our shareholders finding that rate balance is a challenge. Let's be clear. I think we have made significant programs in terms of gaining that, bringing some of the more I say earlier stage assets in for future longer term potential as well as building out some of the near-term development opportunity such as our investment in the Bakken oil play and North Dakota which complemented our position that we already had held in Montana.

As far as the investor base is concerned, we still see the dividend component as a significant part of how we give value to our shareholders. But I think there is also a reality in terms of what's taken place in the basin overall in the last five or 10 years and that’s the nature of the resource and what’s being accessed through the improvements in technology.

And so I think as an oil and gas company that world has changed and we are changing with it. So again we are looking to give investors the benefit of a dividend, but also combine with growth component which speaks to I would say longer terms of sustainability through your own organic growth.

Operator

Your next question comes from Jason Frew from Credit Suisse.

Jason Frew - Credit Suisse

You gave a scenario around CapEx and growth of 2013 at your Investor Day this year. I am just wondering do you have any thoughts or updates that you may want to share on next year in that perspective and maybe how allocation might look in light of cost and progression that you are seeing in your plays?

Gordon Kerr

Well I think generally we will be coming up with our 2013 guidance but directionally to the extent that we don't make significant progress on some of our initiatives and we really have to look at our capital spending program going into the 2013 timeframe. Can we continue to invest at the same level that we have this year. Having said that, the opportunities that we have and where we've been investing our funds we believe are giving us access to increase the potential for additional increasing cash flows. And a lot of that is going to be driven by what happens within obviously the commodity price space. But that's directionally all I would be prepared to tell you at this time Jason.

Operator

I have no further questions in queue. I will turn the call back over to presenters for closing remarks.

Gordon Kerr

Actually in the real time world that we live in I think, Greg, Ian can come back to you on your question on the 24 wells. So we will conclude with that and thank everybody while Ian has finished his remark.

Ian Dundas

Yeah Greg. I came close, but let me give you a little more color and I do appreciate the significance, maybe not as much for us, but understanding what's happening in the Marcellus here.

So, I'll break down the categories. So, we put into that drilled, not completed and then also completed, not producing. We gave you the net number, the gross number. So we would have participated in 260 wells that are drilled and not completed.

In addition, there would be 68 wells that are completed and are producing. And again, the three big participants, operators in that would be EXCO, Chief and Chesapeake. And then based on our work and interest, the Chesapeake stuff would be I guess the largest number of those gross wells.

Gordon Kerr

Okay, well with that thanks everyone for joining us today and have a great weekend.

Operator

This concludes today’s conference call. You may now disconnect.

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