Aug 7, 2015
Executives
Drew Mair - Manager, Investor Relations Ian Dundas - President and Chief Executive Officer Rob Waters - Senior Vice President and Chief Financial Officer Ray Daniels - Senior Vice President, Operations Eric Le Dain - Senior Vice President, Corporate Development Commercial
Analysts
Greg Pardy - RBC Kevin Hanrahan - KMH Capital Advisors Patrick O'Rourke - AltaCorp
Operator
Good morning. My name is Sharon and I will be your conference operator today.
At this time, I would like to welcome everyone to the Enerplus Corporation 2015 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] Mr.
Drew Mair, Manager, Investor Relations, you may begin your conference.
Drew Mair
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. And 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 6:1 energy equivalent ratio, which does not represent the current value equivalent. The information we are 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 statements filed on SEDAR and EDGAR and available on our website at enerplus.com.
Following our discussion, we will 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, I will turn the call over to Ian.
Ian Dundas
Thanks Drew. Good morning, everyone and 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 to 46,000 barrels per day for the year.
We continued to see improved cost performance across the business. Although a weakening and weakened Canadian dollar has put some pressure on our reported U.S.
dollar expenditures, our improving cost performance has more than offset that effect and we are maintaining our capital guidance at $540 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.
Funds flow was up significantly from the previous quarter at $160 million. This was on the back of higher production, lower costs and improved oil prices.
During the quarter, we closed on our previously announced non-core asset sales for proceeds of $188 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 the strong balance sheet, conservative payout, low maintenance capital and strong capital efficiencies, we have significant flexibility to navigate as we move through this market. And with that, I will now pass the call over to Mr.
Rob Waters.
Rob Waters
Thanks, Ian and good morning everyone. We are saying tangible cost saving results.
We are decreasing our annual operating and G&A costs by a combined $0.65 per BOE. Operating cost guidance has been reduced from $9.75 to $9.25 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 U.S. operating costs.
Actual operating costs were $8.72 per BOE for the first half of the year. Now, 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 $2.40 per BOE to $2.25 per BOE for 2015.
Year-to-date we are tracking cash G&A of $2.19 per BOE as we continue to manage staffing and administrative costs. Although we are increasing our production guidance, as Ian mentioned we are maintaining our capital spending budget at $540 million despite the weakening Canadian dollar.
We have retained flexibility to adjust to the program somewhat as we move through the year which Ray Daniels will expand upon in a minute. Funds flow increased by 47% to $116 million in the second quarter compared $109 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 $497 million before tax. Unlike IFRS accounting, U.S.
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 has run on a country-by-country basis using proved reserves discounted at 10%. As commodity prices have remained challenged since June 30, there is some 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 U.S.
GAAP, we are not allowed to reverse impairments in the future if prices recover. Our hedging program help support funds flow in the second quarter with a gain of $73 million.
Now, 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 have 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 $7 million cash loss in the second quarter.
The good news is that we mitigated 25% of this exposure in May by entering into offsetting U.S. 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 $89 million of term debt, as they mature, using our bank credit facilities.
The maturing terms 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 tested 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 would become a U.S. domestic issuer.
Keep in mind that we already report in U.S. GAAP.
We passed the test to 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 or adjusted payout ratio, for the first six months of 2015 was 75%. That's right, 75%.
Not only have been – we have been living within our funds flow, we have been paying down debt quarter-over-quarter. Now in the second half of the year, we expect to slowdown 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 a $124 million annually on dividends. And in 2014, we discontinued our stock dividend plan, which is much like a DRIP plan, because of dilation to shareholders.
In conclusion, overall, we remain in a strong financial position. We ended the quarter with debt to trailing 12 months 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 will now turn the call over to Ray Daniels.
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 in Marcellus and Canadian 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 $111 million drilling 5.5 net wells and bringing 9.2 net wells on stream. This drove obvious production in the quarter to about 27,100 barrels of oil equivalent per day, up over 25% from Q1.
We had some notable successes in the quarter and continued to demonstrate best-in-basin well performance. Our operated on-stream wells in the quarter had an average initial day after day production rate of over 2,000 barrels of oil equivalent per day, exceeding our high-end tight curve.
Our best performing on-stream well in the quarter had an IP30 of over 2,500 barrels of oil equivalent per day or 75,000 barrels of oil equivalent in that day after days. We are also very encouraged with the initial production rates of the first two wells on a new pad that was recently brought on stream and are located in what was historically, a less productive area in the southeast part of our land position.
These early production improvements that exceed expectations by over 50% have occurred through strategic evolution of our completion design and we are very excited with the progress we have made and will continue to make. Service costs, efficiencies and technology changes are occurring rapidly.
And it’s difficult to accurately predict what costs may go. What I can’t see is that in 2015, our best long horizontal well drilling complete costs is$ 8.75 million.
Facilities costs vary depending which well on the pad is being tied in. But on average, our surface equipment costs at approximately $1 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 that 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 forecast – sorry our current focus on further cost reductions is on frac design, optimization of flow back and frac water handling and facilities design optimization. Implementing these actions could lead to a further $1 million savings on down spacing 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 eight wells and bring up to 10 net wells on stream 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 a program depending on market conditions. Turning to the Marcellus, there was a continued low level of spending in the quarter at just $12.6 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 basin assets, we have more production data from our operated three horizontal well pad, [indiscernible], 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 will turn it over to Eric.
Eric Le Dain
Thanks Ray. I will 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 lights sweet differentials help support our Bakken differentials as well, which narrowed by $2.35 per barrel quarter-over-quarter to average $9.30 per barrel, a low 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 below 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 $2.09 per MCF. With respect to the ongoing service interruptions and restrictions of the TCPL NGTL pipeline system, the subject anyone use these days, we have been able to limit the impact on Enerplus through holding firm transportation in our key areas and actively managing transportation shortfall at affected locations.
We had on average roughly 5 million cubic foot 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 will turn it back to Ian.
Ian Dundas
Thanks, Eric. In summary, our new wells brought 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, good assets, strong balance sheet and a great team and the decisions we are 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. And with that, I will turn the call over to the operator and we will open up for any questions you may have.
Operator
[Operator Instructions] Your first question comes from Greg Pardy from RBC. Your line is open.
Greg Pardy
Yes, thanks. Thanks.
Good morning. I will jump around a little bit on the questions, but I guess the first one is what does your spending profile look like then in the third and fourth quarters?
Ian Dundas
So, as Rob said, back half of the year spending is less than first half of the year spending. We have said it’s a majority weighted to the third quarter.
Originally that would have been very highly weighted to the third quarter and we have now sort of flattened that out and pushed some of that capital into the fourth quarter to give us some flexibility on the spending, but it would be – our anticipated spend in Q3 directionally would be a bit less than Q2. We will see how that goes and then lower again in Q4.
Greg Pardy
Okay, great. Question I often ask just what’s the backlog of drilled, but uncompleted wells at Fort Berthold right now just as the end of 2Q?
Ian Dundas
So, right now, we have and this is Fort Berthold, Greg, you normally ask about Marcellus.
Greg Pardy
Yes, it’s of less interest in this environment, yes Fort Berthold?
Ian Dundas
Yes. Can you give me a second?
Greg Pardy
Yes. I have got one other question, so do you want to come back to it?
Rob Waters
Yes, sure.
Ian Dundas
Yes.
Greg Pardy
Okay. I guess just the last question is a little bit strategic, but thoughts just around monetizing your non-op production in the Bakken, just what – how are you thinking about that and then could you quantify it for us?
Ian Dundas
So, maybe just talk broadly about portfolio strategy, Greg. We have been really consistent in looking for ways to make the portfolio better on the divestment side, which is what you are 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 acreage. Typical activity in the non-op has been a little bit higher than we have had.
And so, the production split would be a little bit higher weighted to the non-op than you would extrapolate from the acreage splits. And so we are going to keep doing what we have 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 can you just the open the box hasn’t generally been a great idea for people.
We don’t have any particular financial targets around divestment activity. I would say $100 million goals are little long ways these days.
I will leave it at that.
Greg Pardy
Okay, thanks for that.
Ian Dundas
Greg, with respect to your first question, at the end of Q2 we will have 15 drilled uncompleted wells at Fort Berthold.
Greg Pardy
Okay. Thanks Ray.
Thanks all.
Ian Dundas
Thank you.
Operator
[Operator Instructions] Your next question comes from Kevin Hanrahan from KMH Capital Advisors. Your line is open.
Kevin Hanrahan
Hello Ian, congratulations, I thought there were terrific results 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?
Ian Dundas
The short answer is that, not really. The short answer is not really.
We pay taxes in the jurisdictions in which we operate. And so those jurisdictions in the U.S.
have their own tax arrangements.
Kevin Hanrahan
Yes. My next question was around your tax pools, which I think are significant.
Are those only usable against production in Canada?
Ian Dundas
We would have tax pools in areas in which we operate again. Our tax pool coverage in Canada would be quite extensive.
It wouldn’t be as extensive in the United States. In either 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 larger than the U.S. pools.
Kevin Hanrahan
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?
Ian Dundas
I will turn it over to Rob Waters to answer to that question.
Rob Waters
Yes. The test remain a foreign private issuer that really has nothing to do with income taxes in the U.S.
or in Canada. It’s more to do with regulatory compliance.
Because we are listed in Toronto Stock Exchange, we have to comply with Canadian securities regulation. We are also listed on the New York Stock Exchange and so we have some element of U.S.
regulation that we have to comply with. But we have been considered in the U.S.
to be a foreign private issuers, so we can take advantage of, in some situations, what I would call Canadian regulatory rules. And that has just streamlines it and so every year we have to run the tests.
And the test is based on how many of your shareholders are U.S. based and also how much of your assets are U.S.
based. And so, if we were to fail the test, it’s not a big deal, it just means that we have to comply with more securities and SEC regulations in the states than we normally do today.
And there is a fair amount that we already comply with in terms of the SEC regulations. And as we pointed out, we are already a U.S.
GAAP accounting companies.
Rob Waters
Okay. Thanks very much Rob.
Thanks Ian.
Ian Dundas
Sure. Thank you.
Operator
[Operator Instructions] Your next question comes from Patrick O'Rourke from AltaCorp. Your line is open.
Patrick O'Rourke
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 am just wondering across the 13 wells that you brought onstream here. What sort of variation did you see there in terms of high, min and kind of median for those well results and then do you see that geographically.
And then secondly, you talked a little bit about the change in propane on the first quarter call. Just wondering, if any of these stronger results are start continuing to be related back to that change in propane or if you are able to add a little bit more color on that?
Ian Dundas
Yes. So, let me start with the completion design.
So, we have been evolving and modifying our completion design as we have learned with every frac that we do. And so we have got a modified split water completion design just now where we are pumping at higher rates, but we are still able to place about 1,000 tons per foot of propane down-haul.
And so we have got somewhere between 30, 42 stages along a 10,000 foot lateral. And we have five limited entry clusters in these stages.
So, we have been modifying that over the period and we have been changing our pump schedule as well in order to maximize placement of propane. And so as I said earlier, we are very excited by the results that we are achieving.
This year, with the 13 wells that we 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 are all above expectations.
We averaged – as I mentioned, we averaged at 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 first 50 days, is what we said in the last quarter call.
So, we are very pleased with the performance that we are seeing from our frac design.
Rob Waters
Patrick, let me also add one other thing. I guess, in our IR materials, we have given a range of economics to think about tied to I guess a relatively broad sample set.
And in terms of that IP30, I am sorry I am going to switch to barrels for a second, so maybe gross is up by about 10% to put some gas into it, but with the high-end wells, 1600-barrel IP30 and the low-end well 800 and the average 1,200. We haven’t seen that low-end performance in a while and some of that we attribute to high grading in the areas that we are in and some we attributed to this new completion design, where the one we just talked about, which the last quarter that DMX well in an area, we would have thought might be at the low end and meaningfully exceeded it.
So, it’s – things are moving in a good direction. Some of its early kind of data for some of these completion designs, but we are pretty encouraged by it.
Patrick O'Rourke
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 cost from the service provider that might not necessarily be there with permanent fee if we get into a better environment?
Ian Dundas
Yes, as we work through all I would say it’s about 50-50. Yes.
Patrick O'Rourke
Okay, thanks a lot guys.
Ian Dundas
Thanks, Patrick.
Operator
[Operator Instructions] We have no further questions at this time. I turn the call over to the presenters.
Ian Dundas
Alright. Well, thank you everyone.
I appreciate your interest this morning and have a good day and enjoy the rest of your summer. Thank you.
Operator
This concludes today’s conference call. You may now disconnect.