Enerplus Corp (ERF) 2012 Q2 法說會逐字稿

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 speaker's 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.

Thank you, operator, and good morning, everyone. I've like to welcome you to our second-quarter conference call. Gord 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 results. 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 Operations; 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 of forward-looking information found at the end of our news release issued this morning, and included within our MD&A and financial statements 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. 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 6 to 1 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'll also have a replay of this call available later today on our website.

With that, it's over to you, Gord.

Well, thanks, Jo-Anne, and good morning, everyone. 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'm going to turn 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. The daily production averaged 82,100 BOE per day, and that's 4% higher than the first quarter, 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 water flood properties. Our crude 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 CAD209 million on capital expenditures during the quarter, 80% of which was focused on our oil assets. The majority of spending continued to be on our tight oil play in the Williston basin area of North Dakota, and we continued 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've increased spending on infrastructure related to pipeline connecting our wells to both 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 costs were on track with our forecast for the quarter of CAD10.78 per BOE, and G&A expenses were CAD2.81 per BOE, including both cash and equity-based compensation. Our fund flow during the quarter was CAD147 million, down 10% versus Q1 but ahead of analysts' consensus of CAD131 million. Higher oil production volumes during the quarter provided additional support to our cash flows.

We took the three important steps during the quarter to manage our balance sheet. First, we issued CAD405 million of long-term senior unsecured notes at approximately 4.4% coupon rate, and the proceeds of this issue were used to reduce the borrowings 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 drift, 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 drift.

Thirdly, we reduced our monthly dividend from CAD0.18 per share to CAD0.09 per share. As a result of these measures and our activity in the quarter, our debt to the 12-month trailing fund flow was 2 times, and 68% of our CAD1 billion line of credit was available to us at the end of the quarter.

We also continued to increase our hedge position to predict our 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 $96 per barrel WTI, and now have 14,500 barrels per day of our 2013 net volumes hedged at over $100 per barrel WTI.

With the recent improvement in natural gas prices, we have put in place floor protection on 23 million cubic feet per day of natural gas in 2013 at a price of CAD3.17 per MCF at AECO. We will continue to look for opportunities to add to these hedged positions under our hedging strategy as we move forward.

I'll now turn the call over to Ian to give you more details on our operations during the quarter.

Good morning. Our focus this year has been on executing our capital spending program to deliver on our growth targets, as Gord had 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 CAD140 million here during the quarter. We drilled 7 net wells and brought 8 net wells to production. Year to date we've drilled 16 net horizontal wells and brought a total of 11 net wells on stream.

Our primary focus continues to be long Bakken wells, but we have brought 4 Three Forks wells on stream 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 a key focus area. As you may recall, we had targeted at the beginning of the year to reduce our D&C costs over the course of the year for a long lateral to about CAD10 million. The completion would represent two thirds of that total cost.

Although costs have stabilized in the second quarter, and we've made some significant progress in certain areas, we have not yet achieved that goal. Year to date, our D&C costs have averaged approximately CAD12 million for our long wells, which are typically 9000-foot laterals, 23 to 25 stages, and we continued to use high-strength ceramic proppant.

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 had been experiencing on average.

Current drilling costs for our remaining rigs are in the CAD4 million to CAD4.5 million range, which will lower our drilling costs by more than CAD500,000 per well on average. We are also continuing to focus on optimizing our completion costs. We have recently tested the use of fewer frac stages and less proppant. Although we have seen lower costs, additional runtime is needed to determine whether the 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 padded drilling in 2012.

However, subsequent to the quarter, we did complete a four-well pad and achieved D&C costs at approximately CAD11 million per well. A final cost and costs in the basin -- at the macro level, we have seen costs stabilize, but not necessarily fall in any meaningful way.

As we look at activity levels currently and look forward through the course of the year, and at 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 back end of the year and into 2013.

Although we continue to target cost reductions below the CAD12 million level, the economics of our program at Fort Berthold continue to be robust at current costs. Using a CAD12 million well cost, and based on the current forward strip, rate return on our long Bakken wells is approximately 50%, with PV10 at CAD11.5 million and a recycle of over three times.

Even though we operate at approximately 90% of our lease holds, we did see a significant increase in the level of nonoperated spending over our original expectations. Initially, we were expecting a modest level of nonoperated spending given the limited amount of nonoperated acreage. However, year to date we have spent approximately CAD35 million on nonoperated activity, and expect spending will continue at similar levels over the remainder of the year, which has contributed to an increase in spending in this area.

Defray in the on streams -- initially we were expecting somewhere in the range of 1 net on stream this year. Looking forward, we think that's going to be in the 4 to potentially 5 net wells.

Finally, we have seen some increase in the scope of our infrastructure buildout 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, links to 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 CAD25 million range this year, 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 continued to drill through break of the Med Hat Glauc C in preparation for our EOR project.

We also recommenced our Southeast Saskatchewan drilling program after break up at Freda Lake in the Ratcliffe trend. We continue to have positive results in this area, with our most recent well coming in above expectations, producing 324 barrels of equivalent per day during its first week.

At Giltedge, we continue to advance on our polymer injection project. Overall, the project is generally on track; however, timing of P production is somewhat behind, as we have worked 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 over 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 production of this pilot and determine our go-forward plans once we are injecting as planned and we see peak 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. In 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 nonoperated partners in northeast Pennsylvania, as they focus largely on acreage retention. Rig counts have dropped from earlier in the year, and we are 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 meet lease obligations. We now have a total of about 24 net nonoperated wells either waiting for full completion or the tie-in this reason region.

Production is growing, as we produce an average of 37 million cubic feet of gas a day during the second quarter. However, we are tempering our expectations for exit from the Marcellus to 60 million cubic feet a day, down from our original expectations of 70 million 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 to see activity levels across our entire operations moderate in the second half of the year, and we are closely monitoring our spending levels.

In summary, I am quite encouraged by operations. We are seeing strong oil growth out of Fort Berthold. We are continuing to extract value out of our oil water plugs. We are seeing very good results in our deep gas assets in Ansell and are maintaining the opportunity set in our nonoperated Marcellus acreage.

With that, I'll turn the call back to Gord.

Thanks, Ian. Looking at our guidance for the remainder of the year, and due to the increased spending at Fort Berthold, we are increasing our capital spending guidance to CAD850 million versus our original estimate of CAD800 million. We also increasing our annual average production guidance from 83,000 BOE a day to 83,500, recognizing the incremental production associated with the nonoperated spending at Fort Berthold.

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

On the cost side, we are on track to meet our operating cost guidance of CAD10.40 per BOE, and we are reducing our G&A guidance to CAD3.30 per BOE from CAD3.55 per BOE, due to the 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 off 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're also continuing with our plans to monetize our equity portfolio. And we've now expanded our plans to include the possible sale of other non-core producing assets to help retain our financial flexibility through 2012 and into 2013.

To conclude, we're continuing with our execution on our capital spending plans, with the majority of the spend focused on our oil projects, working to advance our early-stage resource plays, and progressing on our funding initiatives.

With that, I'll turn the call back over to the operator, and we'll take questions.

(Operator Instructions) Greg Pardy, RBC Capital Markets.

Hi. Good morning. I'll hit you with four quick ones. Just curious as to where you think cash taxes will shake out for 2012? Second, the CAD25 million of third-party capital in the Bakken, I'm just wondering if that's already embedded in the revised CapEx of CAD850 million, or whether that possibly would be at in addition to?

And just interested about what you're seeing from an IP rate standpoint in the Bakken. And then the last thing is 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 attached to that? Thanks.

Okay, Greg. So I kind of have three or four questions -- cash tax; the CAD35 million in spend associated with the nonop that's built into the CAD850 million; IP rates on the Fort Berthold, I think you said; and then COG with regard to the 24 net wells. So let me let Rob Waters, our CFO, address the cash tax question.

Hi, Greg. Our guidance on cash taxes hasn't changed, so what we've been saying, and we still adhere to, is in the context of today's current commodity price environment -- and we don't expect any material cash taxes in Canada until after 2015, and that's because we have sufficient tax pool 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 pool coverage there. And of the tax we're paying, most of it is what they call alternative minimum tax that we can recover against future taxes.

So I think today we have paid, if you look at the first half of the year, about CAD4.5 million in cash taxes as a company. Most of that was in the US. And if you do the math on the US cash flow, it turns out to about 3% of US cash flow.

So whether it's 3% to 5%, it's a bit of a rounding error. So we're kind of on track with guidance there. Extrapolating for a full year, and again, it depends on what oil price you're using in your model, you'd expect cash taxes in the range of about CAD10 million, just 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 CAD44 million of cash taxes, but I 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 is happening this year.

Okay. That's great. Thanks.

With respect to the CAD35 million with regard to the -- CAD25, sorry. Okay, shave CAD10 million off already. It is built into the CAD850 million, Greg. And I'll let Ian answer the questions on the IP rates and the 24 net wells you referenced.

Hey, Greg. Okay. I'll start with the trick 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'd say -- we've got largely three operators there with various working interests. I'm going to say it's 150 net wells.

There's a lot of 25% to 30% stuff, but we're drilling some wells at Chesapeake at very low working interest that are quite impactful. So we'll come back to you on that number, but it's at that level.

Okay. So IP's EUR performance. So let's talk reserves. We have a type well for a long Bakken well completed with ceramic based on two wells per 1280 spacing unit that's 800,000 barrels, and then a bit of gas and liquids on top of that. And we are tracking to that level, still, so that's what we'd still anticipate booking at the end of the year.

The IP answer is a little more complicated. Our type 30 day IP is 1,100 barrels a day, again, for that same well. That would assume effectively unrestricted flow. That's incompletion and unrestricted flow the first 30 days.

We have been tracking that level. Of late, though, we are testing whether we should potentially be restricting flow a little bit there, choking back those wells, the theory being we might enhance long-term performance, potentially improve cost structures -- so enhanced economics, although IP 30 a little bit lower; IP 90 about the same, we would think.

So I guess I'm not updating those numbers yet, since we're in the process of working our way through that right now, but if we decide that that's a better approach, you'll probably see a little bit downward pressure on the IP 30 and real similar economics.

Okay. And the 1100 BOE a day, then, is that a BOE or is that the oil number?

That's an oil number.

That's the oil number. Okay. Thanks very much.

Yes. And that's all Bakken. We don't have enough data points to -- we just don't have a large enough sample set to state definitively what the Three Forks look like. We've been running Three Forks at about 70% of rate in reserves relative to those Bakken wells. I'd say we are tracking that. We have some wells that the Bakken -- sorry, Three Forks wells that actually look like a good Bakken well. Some that are under that, but it's still a little bit early to do something other than that 70% number.

Okay. Thanks, all.

(Operator Instructions) 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?

Yes, I think by large it's been in our Canadian operations, because we continue to focus our spend within, again, Fort Berthold region. So Ian, do you want to add further color to that?

Yes, that would be largely it. Initially in the year we would have talked about floor rates, operating rigs going to three rigs in North Dakota, and now that's four going to two, although the net well count looks about that same. So 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 forecast 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 US tight oil.

Okay. Thanks. And then my second question is just wondering if you could give us an idea as to what employee turnover is looking like at this point?

I guess in the aggregate sense, and we kind of follow whatever the trends in the industry in that, and it's not dissimilar to what we're 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 skill sets in our industry, but I think we're seeing some stabilization in that area, too.

Okay, great. Thanks, guys.

(Operator Instructions) Roger Serin, TD Securities.

Morning, everyone. So I have three questions. When you say exit rate, are you thinking December, December 31?

We're really thinking December.

Okay.

We can't predict that actual -- (laughter)

Well, it'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's that?

(laughter) Those are your words, (inaudible).

Okay. So next question. When I think about pricing of the Marcellus gas volumes, there's 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've got the two things going on, the transportation and then the BTU adjustment. Could you give us some color on how we should think about pricing of your Marcellus gas?

I'd probably ask Eric to answer that question, given that is his area of expertise.

Sure. 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 that zero basis differential to minus 5 type range. We see that continuing.

To NYMEX.

Versus NYMEX, yes.

Okay. DRIP. So in this quarter when you change your program, it looks to us like you're DRIP participation dropped in half. You think that will pick up as people get more familiar and maybe 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 DRIP program?

I think we commented, Roger, that we see our participation rate has actually increased, certainly with the reductions in dividend, the absolute flow of funds back in. But you know, I think as more of the information gets out, in terms of the ability to participate in this program, we'd anticipate that we'd see that maybe increase some more.

And keep in mind that we've cut our dividend in half, too, Roger. So, yes.

Okay. Last question, I think. Can you give us some timelines on, what 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.

The process, as I indicated, has been commenced. We kicked this off in July. We haven't set firm bid dates right now. We're in the process of engaging with parties in terms of execution on TA's, as well as having had all of the materials prepared and ready for access.

And so we're early on that. I expect as we move through the course of the year, and towards the back end, we'll have further clarification on where we stand on the initiative now. But I'd say right now we're more encouraged by what we're seeing, and that's why, as I said, we've put the focus on the Duvernay and the Montney. We really see some good interest.

Okay. Thanks very much, everybody.

Gordon Tait, BMO Capital Markets.

Good morning. You've answered most of the questions I had. Maybe just a little bit more on the Marcellus. You still have some 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 you're spending commitments are and what you would need to see to meet those obligations?

Well, I don't know that we would actually connect so directly with what's happening in Marcellus in isolation. Certainly, a significant part of our gas production is still based within Western Canada. So as I said earlier, we put some put protection in place on a 23 million cubic feet a day of our gas production for 2013, and so we have retained all the upside.

So we're still, I would say, somewhat on the bullish side in terms of -- and it's a relative term these days, but in terms of where gas prices can go. So we'll continue to watch for opportunities to maybe shore up some additional put type protection, and if we see improvements in prices to a point where we want to swap, we would not be adverse to mix swapping some of our gas as well.

And Gordon, our Marcellus carry commitment is now down to CAD4.6 million, so the carry obligation in the Marcellus is down to a pretty nominal amount.

Yes, I would suggest by this point, and that was at the end of the second quarter, it's sure. It's done.

Gordon, I'll just add one more comment to -- we have -- I mean, these are big ships that take a little while to turn these companies, our partners in particular. And notwithstanding we've seen a bit of recovery, we are not anticipating a rapid turnaround in that drilling this year. It will take a bit of time.

Commitments are being dropped as we speak, and I think you'll pick up the tone -- we see, I'd say, more risk to the downside in terms of activity this year than upside. It will turn next year, potentially, if we see continued strength.

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

Okay. Thank you.

Bruce Robinson, Equity Pacific.

Good morning. And I want to say that your progress on the production side is very comforting. But I'd like to, if I may, ask you to take sort of a broader brush 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 perceive your unitholders, 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?

Well, that's a great question. As we've transitioned the asset base to try to find the right balance between bringing growth into the portfolio and at the same time staying committed to the dividend as part of the value proposition for our shareholders -- finding that right balance is a challenge. Let's be clear.

I think we've made significant progress in terms of doing that, bringing some of the more, I'll say, earlier stage assets in for future long-term potential, as well as building out some of the nearer-term development opportunities, such as our investment in the Bakken oil play in North Dakota, which complemented the position that we already had held in Montana.

As far as the investor base is concerned, we still see that the dividend component is a significant part of how we give value to our shareholders. But I think there is also a reality in terms of what is taken place in the Basin overall in the last 5 to 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 combined with a growth component, which speaks to, I'd say, longer-term sustainability through your own organic growth.

Thank you.

Jason Frew, Credit Suisse.

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

Well, I think generally we'll be coming out 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, and 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 increase in 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.

Okay.

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

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

Hey, Greg. Yes, 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.

We put into that drilled not completed and then also completed, not producing. We gave you the net number, the gross numbers. 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 aren't producing.

And again, the three big participants -- operators -- in that would be EXCO, Chief, and Chesapeake and then based on our working interest, the Chesapeake stuff would be, I guess, the largest number of those gross wells.

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

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