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Enerplus Corporation (NYSE:ERF)

Q2 2014 Results Earnings Conference Call

August 08, 2014, 10:30 am ET


Jo-Anne Caza - Vice President, Corporate and Investor Relations

Ian Dundas - President, Chief Executive Officer, Director

Eric Le Dain - Senior Vice President - Corporate Development, Commercial

Ray Daniels - Senior Vice President - Operations


Patrick Bryden - Scotiabank

Kyle Preston - National Bank


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 2014 second quarter results. 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. Thanks for calling in. This morning, Ian Dundas, our President and Chief Executive Officer will be providing an overview of our results for the second quarter that we have released. Ray Daniels, our Senior Vice President of Operations will also give some additional detail on our capital spending and our operational performance for the quarter. Eric Le Dain, our Senior Vice President of Corporate Development, Commercial will give a little color on our realized pricing. And we also have Rob Waters, Senior Vice President and Chief Financial Officer on the call today.

Our financials have been prepared in accordance with the United States generally accepted accounting principles. All discussions of production volumes today are gross company working interest basis and all financial figures are in Canadian dollars unless otherwise specified. Conversions of natural gas to barrels of oil equivalent are done on a 6:1 energy equivalent conversion ratio which does not represent the current value equivalent.

The information we are discussing today contains forward-looking information. Listeners are asked to review our advisory on forward-looking information to better understand the risks and limitations of this type of information. This advisory can be 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

Following our discussion, we will open up the phone lines and answer any questions you may have and we will also have a replay of this call available later today on our website.

With that, I will now turn the call over to Ian.

Ian Dundas

Good morning everyone and thanks for dialing in. Q2 was another quarter of strong consistent operational execution delivering profitable growth for Enerplus. Production grew again this quarter averaging about 104,000 BOE a day, a record level for us. This is up 5% from the first quarter and a 15% increase from the same period a year ago. The growth was led by strong increases in our North Dakota light oil play, where production was up 14% from the first quarter and in the Marcellus, where production was up 5% from Q1.

Capital spending was $204 million, in line with our expectations. The majority of our activity was focused on drilling in the North Dakota, Bakken and Three Forks and in Marcellus. We drilled 14 net horizontal wells in our four core areas in the quarter and brought 19 net wells onstream. On the cost side, operating costs were essentially flat quarter-over-quarter and cash G&A expenses were down about 15% per BOE.

Our fund flow was $213 million or $1.04 per share, up compared to the same period a year ago, but down slightly from the first quarter. Our higher production and higher crude prices were offset by lower realized natural gas prices during the quarter. AECO and Nymex gas prices both fell and we saw continued pressure on Marcellus basis differentials. While our long-term pricing contracts provide some production, price differentials widened significantly in the Marcellus. Realized prices average $1.50 U.S. per MCF below Nymex during the second quarter. Eric will get into some additional detail on our pricing outlook in a few moments.

We continue to add to our hedge book for 2015. We swapped half of our oil production for the first half of 2015 at about $93.60 U.S. per barrel and have about a quarter of our oil production swaps for the second half of 2015 at similar prices. Our debt to trailing 12 month fund flow ratio dropped from 1.6 times a year ago to 1.3 times at the end of June and our adjusted payout ratio was 120% for the quarter.

With the growth in production and fund flow, we continue to demonstrate the sustainability of our business. Dividends paid to shareholders, net of participation in the SDP represented roughly 25% of our fund flow during the quarter. Participation in our Stock Dividend Program during the quarter has fallen to less than 10% of shares outstanding. In April, we removed the discount associated with the purchase price of new shares as we were comfortable with the dilution associated with the program. We do not need the equity proceeds to maintain our financial strength.

Based on our results year-to-date, we are increasing our annual average production guidance by 4,000 BOE per day for 2014. We now expect production to average between 100,000 and 104,000 BOE per day. We are maintaining our liquid guidance. We continue to expect liquids production to grow throughout the year, averaging 44,000 barrels per day. This increased production guidance is despite the anticipated sale of between 2,500 and 3,500 BOE per day of non-core largely gas weighted production which we anticipate closing in the fourth quarter.

Our capital spending, year-to-date is on track. However, with the strength our balance sheet and the anticipated proceeds from our non-core divestments, we are evaluating opportunities to modestly increase spending in our core areas. At this time, we are maintaining our capital guidance at $800 million but plan to review spending levels in the third quarter.

Our guidance for operating costs and cash, general and administrative cost is expected to improve with our increase in production. Annual op cost guidance will drop to $10.10 per BOE from $10.25 previously. And cash G&A guidance will decrease to $2.30 per BOE from $2.45.

I will now pass it to Eric Le Dain who will provide some additional details on our realized pricing in the Marcellus.

Eric Le Dain

Ian mentioned that our basis differential was minus $1.50 U.S. per MCF for our Marcellus portfolio in Q2. Year-to-date, we have averaged minus $1.20 U.S. per MCF versus Nymex. I think everyone on the call understands the story. Production growth for the industry remains strong in the Marcellus in Q2 but as importantly demand was moderate due to temperature and the relative price of coal versus natural gas and of course sufficient regional takeaway capacity is not yet in place. Spot gas differentials at Transco Leidy and Tennessee Zone 4 fell to around minus $2.25 U.S. per MCF in the May and June period.

We are forecasting our realized Marcellus differential at minus $1.50 U.S. per MCF for the remainder of 2014, which means we are adjusting our full year 2014 forecast from minus $1 U.S. per MCF as previously said to minus $1.35 U.S. per MCF. It is important to keep this projected job of $0.35 per MCF in perspective. The funds flow associated with the higher production in the Marcellus is an offset to this job.

As we have said before, we don't see the opportunity for a significant improvement in the Marcellus basis in Northeast Pennsylvania, the core of our production area, until the 2017 timeframe, by which time, up to five BCF a day of proposed pipeline debottlenecking directly targeting Northeast Pennsylvania is expected to be in service.

On the crude side, a narrowing in Canadian crude differentials was balanced by a widening of our North Dakota and Montana crude differentials to minus $14.55 U.S. per barrel during the second quarter, up from minus $11.85 U.S. per barrel in the first quarter. This was mainly due to more of our growing North Dakota production shipping by rail in the quarter and rail differentials widening. We continue to expect an annual average discount of $13 U.S. per barrel against WTI at the field gate for our U.S. crude production in 2014.

I will now turn things over to Ray to speak more about our operational results for the quarter.

Ray Daniels

Thanks, Eric. We saw positive operational results on many levels during the second quarter. Spending was just over $200 million with the majority of our drilling being in Fort Berthold, North Dakota and in the Marcellus, Pennsylvania. Combined, these two core areas attracted 70% of our total spend in the quarter. Approximately $100 million was invested in Fort Berthold advancing our drilling program with seven wells drilled and five wells brought onstream. Daily production from North Dakota reached a new high of almost 21,000 barrels of oil equivalent per day, up 14% from the first quarter.

At Fort Berthold, we continue to evolve our completion technique, test tighter density well patterns and test the lower benches of the Three Forks. As we presented at our Bakken presentation in June, we brought our two top performing wells onstream in April, one in the Bakken and one in the second bench of the Three Forks. Each well had an average density initial production rate of approximately 2,400 barrels of oil and each came to more than 70,000 barrels of oil per well in their first month, and both wells continue to look strong.

Our operating netback for Fort Berthold was almost $55 per BOE in the quarter and generated net operating income of about $104 million. On June 18, we announced that our drilling inventory in Fort Berthold increased by 125% to 330 future net drilling locations as a result of our 250% increase in our estimate of economic contingent resource. This drilling inventory is based upon a six to eight well density pattern per drilling spacing unit and with our current pace of activity, this would give us 16 years of future drilling potential.

The changes in our completion technique has also driven a positive shift in initial production rates which have substantially improved the well economics. With a $95 flat pricing assumption, our 800,000 barrels EUR type well is now expected to payout in just 1.4 years compared to 1.7 years under type curve assumptions and IRR on these wells are in excess of 100% compared to 60% previously. Taken together, this has driven a 50% improvement in our capital efficiencies in Fort Berthold.

As a result of our drilling and development activities over the past three years in North Dakota, we have significantly increased the value of this asset for shareholders. In total our U.S. oil assets in North Dakota and Montana produced nearly 27,000 barrels of oil equivalent per day during the quarter, just over 25% of our corporate production.

Our crude oil waterflood portfolio in Canada was just over 20,000 barrels of oil equivalent per day in the quarter, up slightly from Q1. Capital spending was just over $28 million during the quarter with approximately two wells drilled and seven wells brought onstream. These properties are a core part of our portfolio as the free cash flow they provide combined with their lower investment profile and low decline matches our growth and income strategy. They have generated free cash flow of over $33 million in the quarter.

Two of the largest Canadian oil projects are our Medicine Hat Glauc C and Brooks project. Based upon success of our polymer pilot project at Medicine Hat, planning is now underway to build a second polymer project at Medicine Hat for startup in late 2015.

We have also started drilling in the Lower Mannville at Brooks and expect to drill about 20 wells this year as part of a 60 well program over the next three years. We have drilled, completed and tied in only two wells so far. So we are very early days in the program. Of these wells, one well is above and the other well below type curve. We are recommencing drilling later this month.

Looking at our natural gas side of the portfolio, gas production has grown by 25% over the past year. This is being led by the significant increase in production from the Marcellus, which reached a record 190 million cubic feet a day in the quarter, up almost 10 million cubic feet a day from Q1. Similar to what we are seeing in North Dakota, enhanced well completions using more proppant and more frac stages continues to improve well performance.

However, increased production in the region has resulted in bigger prices. Consequently, we expect to see a slowdown in drilling activity towards the end of the year and continuing into 2015. As mentioned in Q1, we have drilled and completed two Duvernay wells to-date in 2014. One well is currently on production and we expect to bring the second well on production sometime in the third quarter. We will be in a better position to talk about these well results in the fourth quarter.

Overall, we are very pleased with the results from our capital program to-date in 2014. We are on track with our spending and ahead of expectations on production. Based upon our revised guidance, we are poised to deliver above average production growth of 14% year-over-year.

I will now turn the call back over to Ian.

Ian Dundas

Thanks, Ray. So in summary, the operational momentum we have established over the last two years continues. The sustainability of our business continues to improve and we are delivering above average growth in both production and funds flow year-over-year. Our balance sheet is strong. We recently entered into agreements for a $200 million U.S. offering of senior 12 year amortizing, unsecured notes at a fixed-rate coupon of 3.79%. We expect to close the offering in early September and we will use the proceeds to pay down our bank debt, further improving our financial strength.

We are well-positioned with a portfolio of both oil and gas projects in Canada and the U.S., with our deep inventory of economic future drilling locations. We believe we will continue to create value for our shareholders through a disciplined capital spending program and are focused on achieving our operating and financial targets.

With that I will turn the call over the operator and we will open it up for any questions you may have.

Question-and-Answer Session


(Operator Instructions). Your first question comes from Patrick Bryden with Scotiabank. Your line is open.

Patrick Bryden - Scotiabank

Good morning, everyone. Just wondering if you might be able to give a little bit more elaboration on the Duvernay. I recognize it is probably premature in terms of rates, but is it possible to get a sense for how the drilling and completions went versus what you would have expected? Thank you.

Eric Le Dain

Good morning, Pat. I think it is premature. We have just commenced production on that first well and as Ray said, the second one was not on yet. Generally speaking, things went as we would have anticipated. It cost a bit more than we expected at the front end, but I don't think we know a lot right now that we are willing to talk about. It will really be a Q4 thing, as we get more information. As you think about that project for us, one of the reasons Q4 disclosure makes sense is, we will give a little color there as we talk about our 2015 spending plans and how it relates to the Duvernay. It is still very early days for us in that project as it is for lots of people. For those who aren't familiar, our project is in Willesden Green, which has less activities than in the Northern Kaybob region. So as we think about 2015, there is a couple of outcomes there. One is very, very modest spending. I think, but even at the higher end, the program would probably only look similar to this year, maybe a little bit more. But it is really a next quarter thing for us.

Patrick Bryden - Scotiabank

Okay. Great, thanks, and then lastly just for me. Can you maybe elaborate a little bit further on Marcellus pricing dynamic for us and what you are seeing in the area and how we should think about that? Thanks.

Ian Dundas

Yes. As Eric said, exceptional production growth. Just exceptional production growth. I think we are sitting at 15 BCF a day right now, which is outside the range of what anyone even imagined several years ago. And so we are full out of the area. And then you layer on some less than average cooling load and you end up with pretty terrible prices at this moment. I think as Eric said, our view is, in some respects this is going to be a little bit of a weather trade over the next couple of years. It will influence it, but there is mostly all of the demand, the takeaway package being built, supply is going to keep up with that probably over the next several years. And so this is sort of the dynamic that we are going to be living with. From our perspective, we are still going to connect on the project. Actually quite robustly economic, surprisingly, part of that is because all of our drilling has been focused in the absolute top tier areas of our project as well. We are thinking typically finding costs in that $0.60 to $0.80 kind of range. We were sitting on a net back of $1.92 in the second quarter. So it's a pretty powerful recycle. Ray mentioned something at the end of his comments that I think is important. We do anticipate we are going to see the pace of spend slow in response to these lower prices. We don't think we will see a lot of it this year, because it is going to slow towards the end of the year but it will be more impact as we move into 2015.

Is there anything specifically you are thinking about?

Patrick Bryden - Scotiabank

No. I think that's great. I appreciate the color.


(Operator Instructions). Your next question comes from Kyle Preston from National Bank. Your line is open.

Kyle Preston - National Bank

Good morning, guys. Just a couple questions for Eric here carrying on this Marcellus Takeaway capacity. So you talked about more capacity coming online in 2017. Just wondering, are you guys working towards locking in some of that capacity now? Or is that too early?

Ian Dundas

I will turn it over to Eric to give you a little more color on what our thinking is there.

Eric Le Dain

Sure. I had said in my comments earlier the Northeast Pennsylvania focus and we are very focused on that in terms of its Takeaway capacity on the specific projects that will help debottleneck that region. The area produce about eight BCF a day out of the 14, Marcellus 15 total including Utica. There are projects coming on late 2014, mid to late 2015, 2016 and into 2017. As Ian said, as we look at the growth potential in the area, the projections of third-party and our own, we see a theme quite balanced against that Takeaway build. And we are adding about a BCF a day this year, and that should have some higher level of certainty and then a BCF a day next year and then it grows to closer to 1.5 out of that region in the 2016 timeframe. So we see that pace of additions that is true movement of gas out of the region as being a pretty good match against the projected supply growth in the area.

Now to your question about our participation. We do and have always been looking at projects. We are considering a number of them at the moment and will be in a better position probably later in the year to update on that site.

Kyle Preston - National Bank

Okay. So as far as 2015, 2016, which should be, we assume that kind of about 5 to 50 basis here, during this time frame?

Eric Le Dain

Yes. Today we see it certainly in 2015. We think it might get a bit better in the 2016, but 2015 will be in the similar range to what we are saying this year.

Kyle Preston - National Bank

Okay. Thanks for that. Just one other question here on that foreign exchange loss that you realized this quarter. How much exposure do you have that going forward as this debt matures?

Eric Le Dain

The foreign exchange loss really wasn't a significant number, Kyle. On the income statement, it was actually a gain of $7 million and on the cash flow statement, it really wasn't that significant. So what might be happening here is, you are probably looking at a settlement of our cross currency interest rate swap, which actually runs through financing activities because it was directly related to a 12 year bond issue we did 12 years ago. And it does not runs through cash flow from operating activities. So rather than get into a big lesson, we could just probably take that offline. The main reason why our cash flow was down quarter-over-quarter, was more due to lower realized natural gas prices like we have been talking about here, like the lower AECO and the wider Marcellus differential.

Kyle Preston - National Bank

Okay. Thanks for that.


(Operator Instructions). At this time, I have no further question in queue.

Ian Dundas

All right. With that, we will wrap up the call. We really appreciate everyone dialing in this morning. Enjoy the last few weeks this summer, and coming in the fall. Thank you.


Thank you. Thanks, everyone. This concludes today's conference call. You may now disconnect.

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