Enerplus Corp (ERF) 2015 Q2 法說會逐字稿

Good morning. My name is Sharon and I will be your conference operator today. At this time I'd like to welcome everyone to the Enerplus Corporation 2015 second-quarter results conference call.

(Operator Instructions)

Thank you. Mr. Drew Mair, Manager of Investor relations, you may begin your conference.

Thank you, operator. And good morning, everyone. Thank you for joining the call.

Ian Dundas, our President and Chief Executive Officer, will be providing an overview of our second-quarter results released this morning. Rob Waters, Senior Vice President and Chief Financial Officer, will be giving details on our financial performance. Ray Daniels, Senior Vice President of Operations, will be providing details on our capital spending and operational performance for the quarter. Eric Le Dain, Senior Vice President of Corporate Development Commercial, will be giving some color on our marketing and hedging activities.

Our financials have been prepared in accordance with United States Generally Accepted Accounting Principles. All discussion of production volumes today are on a 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 to 1 energy equivalent ratio which does not represent the current value equivalent.

The information we're discussing today contains forward-looking information. We ask listeners to please 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 stamens filed on SEDAR and EDGAR and available on our website at enerplus.com.

Following our discussion we will open the phone lines and answer questions you may have. We will also have a replay of this call available later today on our website. With that I'll turn the call over to Ian.

Thanks, Drew. Good morning, everyone. Thanks for joining us today. Clearly our industry is facing a very challenging period with the sustained drop in crude oil prices. As we manage risk through this difficult period our priorities are clear -- maintain our financial strength, focus on productivity improvements and cost control measures, and continue our disciplined approach to capital allocation by only focusing on growth in those projects where returns justify the investment in this market.

We believe our second-quarter results released this morning demonstrate our commitment to these priorities as we saw improved cost structures across the board, meaningful production growth in our core plays, and a further strengthened financial position. Production averaged just over 107,000 BOE per day. This represents quarter-over-quarter growth of 7%, which was primarily driven by increased activity in North Dakota.

We are increasing our annual average production guidance range to between 100,000 and 104,000 BOE per day. This guidance increase accounts for divestments which have closed this year of approximately 1,900 BOE per day. We are also increasing our guidance on our liquids volumes to between 44,000 and 46,000 barrels per day for the year.

We continue to see improved cost performance across the business. Although a weakening and weakened Canadian dollar has put some pressure on our reported US dollar expenditures, our improving cost performance has more than offset that effect and we're maintaining our capital guidance at CAD540 million. Strong volume growth and improved cost efficiencies in other areas of our business have positioned us also to lower our guidance for both operating and G&A costs, which Rob will discuss in a moment.

Fund flow was up significantly from the previous quarter at CAD160 million. This was on the back of higher production, lower costs, and proved oil prices. During the quarter we closed on our previously announced non-core asset sales for proceeds of CAD188 million. Our approach to balance sheet management resulted in reduced debt over the quarter.

As we look to the second half of this year, we expect to maintain our liquids production with continued growth in North Dakota. Our goal of a fully-funded program in 2015 remains intact. With a strong balance sheet, conservative payout, low maintenance capital and strong capital efficiencies we have significant flexibility to navigate as we move through this market.

With that, I will now pass the call over to Mr. Rob Waters.

Thanks, Ian. And good morning, everyone. We are seeing tangible cost-saving results. We are decreasing our annual operating and G&A costs by a combined CAD0.65 per BOE. Operating cost guidance has been reduced from CAD9.75 to CAD9 25 per BOE. The savings are coming from repairs, maintenance and well servicing, along with higher production, and this is offset somewhat by the impact of the weaker Canadian dollar on our US operating costs.

Actual operating costs were CAD8.72 per BOE for the first half of the year. Granted, this is a bit lower than our revised guidance. The reason being, our guidance reflects seasonal spending and facility turnarounds forecast for the second half of the year.

On another positive note, cash G&A expense guidance is also being reduced. It's being reduced from CAD2.40 per BOE to CAD2.25 per BOE for 2015. Year-to-date we're tracking cash G&A of CAD2.19 per BOE as we continue to manage staffing and administrative costs.

Although we're increasing our production guidance, as Ian mentioned, we're maintaining our capital spending budget at CAD540 million despite the weakening Canadian dollar. We retain flexibility to adjust the program somewhat as we move through the year, which Ray Daniels will expand upon in a moment.

Funds flow increased by 47% to CAD160 million in the second quarter compared to CAD109 million in the first quarter of 2015. The improvement can be attributed to higher crude oil prices and increased production, specifically our oil production, offset by continued weakness in realized natural gas prices. In addition, the first quarter had a few one-time charges that were not repeated in the second quarter.

We incurred a non-cash asset impairment charge in the quarter of CAD497 million before tax. Unlike IFRS accounting US GAAP stipulates that we use historical trailing 12-month commodity prices when calculating impairments. The decline in prices for the last three quarters obviously impacted the calculation. The test is run on a country by country basis using proved reserves discounted at 10%.

As commodity prices have remained challenged since June 30 there's an increasing likelihood of another impairment charge in the third quarter. Now, this impairment reduces our net income but it does not impact funds flow. Once again, no impact on cash flow. And under US GAAP we're not allowed to reverse impairments in the future if prices recover.

Our hedging program helps support funds flow in the second quarter with a gain of CAD73 million. We don't expect to maintain this level of hedging gains into the second half of 2015. Although we are well hedged for the second half there is less production, and Eric will provide a more detailed update on hedging in a minute.

We've hedged the foreign exchange for a portion of our revenue stream in 2015. We have been in a loss position for the first half of the year as the Canadian dollar weakened. These hedges resulted in a CAD7 million cash loss in the second quarter.

The good news is that we mitigated 25% of this exposure in May by entering into offsetting US dollar forward contracts. And I guess the bad news is that we didn't offset more of this position as the Canadian dollar continued to weaken after the second quarter.

During the quarter we repaid CAD89 million of term debt as they matured, using our bank credit facilities. The maturing term debt has an average coupon of 6.6% compared to our bank facility at approximately 2.5%. We have one more debt payment of $11 million due in October of this year, and after which we will have no debt maturities until June 2017, with some of the remaining maturities extending out to 2026.

We test our foreign private issuer status every year at the end of June and the test is used to determine whether we continue to file our public documents on the multi jurisdiction disclosure system or whether we become a US domestic issuer. Keep in mind that we already report in US GAAP. We passed the test this year and retained our foreign private issuer status.

As Ian indicated, our plan for a fully funded 2015 program is intact. After adjusting for net A&D proceeds, our adjusted payout ratio for the first six months of 2015 was 75%. That's right, 75%. Not only have we been living within our funds flow, we've been paying down debt quarter over quarter. Now, in the second half of the year we expect to slow down spending with no material increase in debt despite modestly lower hedge protection.

During the second quarter our dividends represented 19% of our funds flow. This compares favorably with our competitors, many of which have much higher dividend payouts. At current levels we spend about CAD124 million annually on dividends. And in 2014 we discontinued our stock dividend plan, which is much like a DRIP plan, because of the dilution to shareholders.

In conclusion, overall we remain in a strong financial position. We ended the quarter with debt to trailing 12-month fund flow ratio of 1.6 times. Our debt to EBITDA ratio was 1.5 times which is the most sensitive ratio in our lending agreements.

With that, I'll now turn the call over to Ray Daniels.

Thanks, Rob. And good morning, everybody.

Operationally we had another safe and solid quarter with some strong well results. As Ian mentioned we had a significant increase in production quarter over quarter. This was driven primarily by our North Dakota asset but both the Marcellus and Canadian Deep Basin also contributed.

Starting in North Dakota where the majority of our spending was focused, we picked up the level of activity from the first quarter and spent CAD111 million drilling 5.5 net wells and bringing 9.2 net wells onstream. This drove average production in the quarter to about 27,100 barrels of oil equivalent per day, up over 25% from Q1. We had some notable successes in the quarter and continued to demonstrate best-in-basin well performance.

Our operated onstream wells in the quarter had an average initial 30-day production rate of over 2,000 barrels oil equivalent per day, exceeding our high-end type curve. Our best-performing onstream well in the quarter had an IP30 of over 2,500 barrels of oil equivalent per day or 75,000 barrels of oil equivalent in that 30 days.

We're also very encouraged with the initial production rates of the first three wells on a new pad that was recently brought onstream and are located in what was historically a less productive area in the Southeast part of our land position. These are early production improvements that exceed expectations by over 50% have occurred through strategic evolution of our completion design. And we are very excited with the progress we have made and will continue to make.

Service costs, efficiencies and technology changes are occurring rapidly and it's difficult to accurately predict where costs might go. What I can say is that in 2015 our best long horizontal well drilling complete cost is $8.75 million.

Facilities costs vary depending on which well on the pad is being tied in, but on average our surface equipment costs are approximately CAD1 million. This would indicate that an all-in drill complete and tie-in costs have come down about 20% to 25% from 2014 levels. We have demonstrated our value approach to capital spend is achieving top decile capital efficiency in the basin, and we continue to look for cost reductions through technology or service costs without compromising this performance.

Our current focus on further cost reductions is on our frac design optimization of flowback and frac water handling and facilities design optimization. Implementing these actions could lead to a further $1 million savings on downspacing wells.

Looking forward for the rest of the year, we are ahead of our 2015 program. We will continue to run with one drilling rig and expect to drill approximately 8 wells and bring up to 10 net wells onstream in the second half of the year, broadly weighted to the third quarter. In addition, we have some flexibility at the back end of the year to moderate the program depending on market conditions.

Turning to the Marcellus, there was a continued low level of spending in the quarter at just CAD12.6 million. Despite the low spend and reduced activity, well outperformance led to a slight increase in average production over the previous quarter to 201 million cubic feet per day. We expect even lower levels of spending in Q3 and Q4 in Marcellus.

Moving on to the Canadian deep Basin assets, we have more production data from our operated three horizontal well pad, Ansell. The results are excellent, with an average peak 30-day production rate per well of about 10 million cubic feet per day. We also have an interest in two non-op wells in the area which are also showing very good test rates.

Overall our assets continue to perform at or better than our expectations. As importantly, we have not let up on our commitment to safety and responsible operations in spite of the challenging market conditions.

And with that I'll turn it over to Eric.

Thanks, Ray. I'll touch briefly on our realized pricing in the quarter and our hedge position. Firstly, heavy and light crude oil differentials in Canada strengthened considerably during the quarter. The strength in light sweet differentials helped support our Bakken differentials, as well, which narrowed by $2.35 per barrel quarter over quarter to average $9.30 per barrel, below WTI during the second quarter.

In the Marcellus, our realized differential to NYMEX widened by $0.07 per Mcf from the previous quarter to average $1.39 per Mcf, bellow NYMEX. Overall as a result of lower NYMEX and AECO benchmark pricing, and continued pricing weakness in the Marcellus, our realized sales prices for gas fell by 19% compared to the previous quarter to average CAD2.09 per Mcf.

With respect to the ongoing service interruptions and restrictions of the TCPL NGTL pipeline system, a subject in the news these days, we have been able to limit the impact on Enerplus through holding firm transportation in our key areas, and actively managing transportation shortfalls at affected locations. We had on average roughly 5 million cubic feet equivalent per day of natural gas production temporarily curtailed during the quarter due to these restrictions.

Turning to hedging, we continued to add to our commodity hedge position for both 2015 and 2016. For the second half of 2015 we have approximately 35% of our expected crude oil production, net of royalties, hedged at an average floor price of $84.58 per barrel. For 2016 we have approximately 34% of our expected crude oil production, net of royalties, hedged at an average floor price of $64.35 per barrel. And this is predominantly done through three-way positions.

We have also added to our NYMEX gas hedging position for the second half of 2015. We are swapped on approximately 47% of our forecasted natural gas production after royalties at an average price of $3.82 per Mcf. For 2016 we have about 9% of our forecasted natural gas production hedged with an average floor price of $3 per Mcf. And this is all done through three-way positions.

With that I'll turn it back to Ian.

Thanks, Eric. In summary, our new wells run on stream in the quarter largely outperformed type curve expectations. We grew both liquids and gas production quarter over quarter. And we saw cost savings in our capital, OpEx and G&A. We increased our production guidance and reduced our cost guidance.

Meanwhile, we actually reduced our debt to funds flow ratio in the quarter. It was a good quarter in a tough market.

As I said at the opening, I believe we are focused on the right priorities as we manage through this challenging commodity price environment. We entered this downturn in a strong position with good assets and strong balance sheet and a great team. And the decisions we're making are allowing us to retain that relative strength. Although it has been a very difficult time for investors, we believe we are well-positioned to continue to navigate through this difficult time.

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

(Operator Instructions)

Your first question comes from Greg Pardy, RBC.

Thanks, good morning. I'll jump around a little bit on the questions, but the first one is: What does your spending profile look like, then, in the third and fourth quarters?

As Rob said, back half of the year spending is less than first half of the year spending. We've said it's majority weighted to the third quarter. Originally that would have been very highly weighted to the third quarter, and we've now flattened that out and pushed some of that capital into the fourth quarter to give us some flexibility on the spending. But our anticipated spend in Q3, directionally, would be a bit less than Q2. We'll see how that goes, and then lower again in Q4.

Okay, great. A question I often ask: What's the backlog of drilled and uncompleted wells at Fort Berthold right now, just since the end of 2Q?

Right now we have -- this is Fort Berthold, Greg? You normally ask about Marcellus.

Yes. It's of less interest in this environment, but, yes, Fort Berthold.

Can you give me a second?

Yes. I've got one other question, so do you want to come back to it?

Yes.

Okay. The last question is a little bit strategic, but -- thoughts just around monetizing your non-op production in the Bakken -- just wondering how you're thinking about that. And then, could you quantify it for us?

Maybe just talk broadly about portfolio strategy, Greg, we've been really insistent in looking for ways to make the portfolio better on the divestment side, which is what you're asking about. It's really been focusing around our core properties, and moving out of the non-core. I don't think it's a great idea to get too much into the specifics on that, but when we think about what non-core -- generally non-op has less strategic value than operated. You talked about non-operated assets in North Dakota. That's a great area, but strategically the non-op piece has less value to us.

On an acreage basis, those non-operated assets would represent less than 10% of our acres. Typical activity in the non-op has been a little bit higher than we've had. So, the production split would be a little bit higher weighted to the non-op, then you'd extrapolate from the acreage splits.

We're going to keep doing what we've always done in lots of cycles, is look for opportunities to find value and make our portfolio better on non-op. That could be oil; that could be gas. What happens in this market? Who knows.

One of the reasons that we have what I think is a really excellent track record in monetization is we maintain flexibility, because it's been a difficult market to monetize. And getting yourself in a box hasn't generally been a great idea for people. We don't have any particular financial targets around divestment activity. I'd say CAD100 million goes a long ways these days. And I'll leave it at that.

Okay. Thanks for that.

Greg, with respect to your first question, at the end of Q2 we will have 15 drilled uncompleted wells at Fort Berthold.

Okay. Thanks a lot, Ray. Thanks, all.

(Operator Instructions)

Kevin Hanrahan, KMH Capital Advisors.

Hello, Ian. Congratulations, I thought that was a terrific result in a difficult time.

I had a couple of questions surrounding the tax rate. I know that the liberal party in Alberta -- the new Liberal party -- raised the corporate tax rate. So, my question is: For your production south of the border in Pennsylvania and North Dakota, is it subject to that higher Alberta tax rate or not?

The short answer is not really. We pay taxes in the jurisdictions in which we operate, and jurisdictions in the US have their own tax arrangements.

Yes. My next question was around your tax pools, which I think are significant. Are those only usable against production in Canada?

We would have tax pools in areas in which we operate again. Our tax pool coverage in Canada would be quite extensive. It would not be as extensive in the United States. In neither jurisdiction are we paying meaningful tax right now. There are some minimum taxes we pay in the United States, but the Canadian pools are quite a bit larger than the US pools.

I see. And your colleague was talking about the test to be a foreign corporation. Are you looking at that because of the tax, or is the tax a minor consideration for Enerplus?

I will turn it over to Rob Waters to answer that question.

The test to remain a foreign private issuer -- that really has nothing to do with income taxes in the US or in Canada. It's more to do with regulatory compliance. Because we're listed on the Toronto Stock Exchange, we have to comply with Canadian securities regulation. We're also listed on the New York Stock Exchange, and so we have some element of US regulation that we have to comply with. But we've been considered, in the US, to be a foreign private issuer, so we can take advantage of, in some situations, what I would call Canadian regulatory rules, and it just streamlines it.

So, every year we have to run the test. And the test is based on how many of your shareholders are US-based, and also how much of your assets are US-based. If we were to fail the test, it's not a big deal. It just means that we'd have to comply with more securities and SEC regulations in the States than we normally do today. And there's a fair amount that we already comply with, in terms of SEC regulations. As we pointed out, we're already a US GAAP accounting company.

Yes. Okay. Thanks very much, Rob. Thanks, Ian.

(Operator Instructions)

Your next question comes from Patrick O'Rourke, AltaCorp.

Good morning, guys. Congratulations on a very nice quarter -- just a couple of quick questions here.

First of all, you talked about the IP30 results in the Bakken there being 2,000 BOEs per day. I'm just wondering, across the 13 wells that you brought on stream here, what variation did you see there in terms of high, min and median for those well results? And then, do you see that geographically?

And then, secondly, you talked a little bit of proppant on the first-quarter call. Just wondering if any of these stronger results are continuing to be related back to that change in proppant, or if you're able to add a little bit more color on that?

Yes. Let me start with the completion design. We've been evolving and modifying our completion design as we learn with every frac that we do. So, we've got this modified slickwater completion design just now, where we're pumping at higher rates but we're still able to place about 1,000 pounds per foot of proppant downhole.

We've got somewhere between 38, 42 stages along a 10,000-foot lateral. And we have five limited-entry clusters in these stages. We've been modifying that over the period, and we've been changing our pump schedule as well, in order to maximize placement of proppant.

As I said earlier, we're very excited by the results that we are achieving. This year, with the 13 wells that we've brought on, I mentioned that the highest one there was 2,500 barrels of oil equivalent per day for the IP30. Generally, our wells are above -- they're all above expectations.

I mentioned that we averaged over 2,000 barrels of oil equivalent per day for the other wells. And last quarter we talked about our Q1 results, which, again, we produced, I think it was 75,000 barrels a day in the first 50 days, is what we said in the last quarter call. So, we're very pleased with the performance that we are seeing from our frac design.

Patrick, meanwhile, I just had one other thing. In our IR materials we've given a range of economics to think about, tied to a relatively broad sample set. And in terms of that IP30 -- and I'm sorry, I'm going to switch to barrels for a second, so maybe gross these up by about 10% to put some gas into it. But we'd be -- the high-end wells -- 1,600 barrel IP30, and the low-end well, 800, and the average 1,200.

We have not seen that low-end performance in a while. And some of that we attribute to high-grading in the areas we're in, and some we attribute it to this new completion design where in -- the one we just talked about, which, last quarter, that BMX well in an area we would have thought might be at the low end, and meaningfully exceeded it. So, things are moving in a good direction. Some of it's early time data for some of these completion designs, but we're pretty encouraged by it.

Okay. That's great. And just one more question here: On the 20% cost reduction that you have seen there, are you able to break that down between what is efficiencies and what is actual reduction in costs from the service provider that might not necessarily be there with permanency if we get into a better environment?

Yes. As we work through it all, I'd say it's about 50/50.

Okay. Thanks a lot, guys.

(Operator Instructions)

We have no further questions at this time. I turn the call over to the presenters.

All right, thank you, everyone. Appreciate your interest this morning. Have a good day, and enjoy the rest of your summer. Thank you.

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