Nov 14, 2016
Executives
Drew Mair - Manager, IR Ian Dundas - President & CEO Jodi Jenson Labrie - Senior Vice President and Chief Financial Officer Ray Daniels - Senior Vice President, Operations Eric Le Dain - Senior Vice President, Corporate Development Commercial
Analysts
John Green - TD Securities Patrick O’Rourke - AltaCorp Capital Kurt Molnar - Raymond James Jason Frew - Credit Suisse Ray Kwan - BMO Capital Markets
Operator
Good morning. My name is Sherrin, and I will be your conference operator today.
At this time, I would like to welcome everyone to the Enerplus Corporation Third Quarter Results Conference Call. [Operator Instructions] Thank you.
Mr. Drew Mair, Manager of Investor Relations, you may begin your conference.
Drew Mair
Thank you, operator and good morning everyone. Thanks for joining us.
Apologies for the delay in the call this morning. We had technical issues, but we are trying to keep this quick.
Before we get started, please take note of the advisories located at the end of today’s news release. These advisories describe the forward-looking information, non-GAAP information, and oil and gas terms referenced today, as well as the risk factors and assumptions relevant to this discussion.
Our financials have been prepared in accordance with U.S. GAAP.
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. I am here this morning with Ian Dundas, our President and Chief Executive Officer; Ray Daniels, Senior Vice President, Eric Le Dain, Senior Vice President, Corporate Development Commercial and Jodi Jenson Labrie, Senior Vice President and Chief Financial Officer.
Following our discussion, we will open up the call for questions. With that, I will turn it over to Ian.
Ian Dundas
Good morning, everyone. I appreciate your attendance this morning, again, I apologies for the delay.
We delivered strong financial results during the quarter, which were underpinned by our continued focus on cost control and solid operational execution. We have made considerable progress executing our 2016 strategy which has been focused on reducing our cost structure, strengthening our balance sheet and continuously improving operational and capital efficiencies.
Our efforts to improve the resilience of our business and increase our margins have delivered meaningful results. Our expectation for full year 2016 operating, transport and G&A costs is now approximately $80 million less than our original 2016 guidance and approximately $115 million less than we spent in 2015.
Our Q4 capital efficiency for 2016 is expected to be in the [16,000 per flowing] barrel range while spending 90% targeting oil development. And we have significantly strengthened our financial position with net debt down 46% since year end 2015.
In short, we remain on track to re-initiate profitable and sustainable growth in 2017. Our preliminary outlook for 2017 capital spending is $400 million, an increase from this year’s $215 million budget.
The majority of the increase spending will be allocated to North Dakota where we have a second operated drilling rig starting in Jan. We expect to deliver meaningful crude oil growth next year; our North Dakota production is projected to grow by 25% on a Q4 to Q4 basis, which will drive total company liquids growth of approximately 15% for the same period.
We remain focused on delivering a sustainable financial plan and expect our 2017 capital program and dividend commitments to be largely balanced with internally generated cash flow at US $50 per barrel for West Texas, and US $3 per Mcf. We expect to produce, provide further details around our 2017 budget later this year.
Looking further ahead into 2018, and under similar commodity price assumptions, we anticipate delivering another year of double-digit liquids production growth while operating at or near cash flow. Turning to some of the other highlights from our release this morning, we have seen promising initial results from our high density test at Fort Berthold optimizing our spacing pattern in the Balkan is a key priority for our drilling program and could have positive implications for our inventory.
Ray will speak more about this. A critical development of our strategic plan has been to high grade our portfolio.
Over the last several years we have had considerable success in divesting low margin, limited upside assets and focusing our efforts on operated, high margin, higher growth properties. Consistent with this portfolio optimization strategy we have entered into an agreement to acquire a high potential, high margin waterflood oil asset in Central Alberta.
Even though this transaction is quite modest in size, it’s highly accretive and we believe the asset will generate exceptional returns. In parallel with this acquisition, we continue to pursue our non-core divestment objectives.
And with that, I will turn the call over to Ray, who will provide some of our operational highlights.
Ray Daniels
Thanks, Ian. I will start with our production in the quarter and the outlook for the rest of the year.
We continue to see strong production across the portfolio in the third quarter and we remain on track to meet the midpoint of our 2016 guidance of 93,000 barrels of oil equivalent per day. Fourth quarter production will be impacted by significant volumes curtailed in the Marcellus in October due to low gas prices.
We expect the impact in Q4 production from this curtailment to be approximately 1500 barrels oil equivalent per day. However, in recent weeks, cash prices in the Marcellus have improved considerably and the curtailed production is now back on line.
In addition to the Marcellus curtailment our fourth quarter Canadian gas volumes have been impacted by our decision to shut in production that was not generating our return. We also divested some minor non-core gas production during the quarter, combing the Canadian gas shut in and divestments of about 1000 barrels of oil equivalent per day.
Notwithstanding these losses into production, our fourth quarter forecast of 89,000 barrels of oil equivalent per day remains unchanged offset by strong production in North Dakota and the Ante Creek waterflood acquisition. Staying with North Dakota, I’ll talk about our objectives for this asset as we move to a larger program in 2017.
Firstly, we plan to re-establish strong production growth from Fort Berthold in 2017 with the addition of a second rig in January we project 25% production growth from the asset on our Q4, 2016 to Q4, 2017 basis. Second, we will continue to drive operational and capital efficiency improvements that are sustainable.
An example of this would be the efficiency gains we have made in drilling, where we have reduced cycle times by over 20% relative to our 2015 average. Our [Indiscernible] well this year was drilled 40% faster than the 2015 average.
We will keep pushing forward on this path of continuous improvement. Our third key objective in North Dakota over the next 12 months is continuing to optimize our development plan; [central] to this will be further testing of well density and completion designs.
We sit in the core of the Bakken with a very lightly drilled acreage position. On average, we’ve only got about two wells drilled per drilling spacing unit.
This gives us significant flexibility to modify the well density in our development plans. In our release this morning, we highlighted some encouraging, initial results from a 500 foot Bakken-to-Bakken high density test.
It is early days, but combined with other industry data points the results are positive in terms of leading to a high recovery factor. We are planning additional density tests in 2017 with varying inter well spacing.
For contact, our current spacing pattern assumes 1400 feet with approximately four wells in the middle of Bakken and four wells in the Three Forks. Clearly, this ongoing density testing could have a meaningful impact on our inventory in North Dakota.
In addition, we will continue our ongoing optimization of completion designs, varying pump rates, cost of spacing and profit and volumes, all in service of improving our capital efficiency. Although we are planning for increased activity, I’d like to emphasize that we have built significant flexibility into our 2017 capital program in North Dakota which will allow us to reduce activity should crude oil prices materially weaken.
In particular, I would note that while we have secured pumping services for the entire 2017 program we have no minimal contractual commitment and can therefore very quickly dial back completions activity if we choose. Moving on briefly to our Canadian operations under Marcellus.
In Canada, activity has been largely focused on polymer and waterflood maintenance activities and we continue to see strong performance from our EOR assets. In the Marcellus we continue to forecast very limited spending for the remainder of 2016.
Directionally, if regional prices continue to firm up we would expect capital spending to increase in the Marcellus in 2017 relative to our 2016 spend. In connection with our 2017 capital plans, we have taken steps to reduce the risk of cost escalation as we have approximately 50% of our capital cost protected through contracting.
Finally, we noted in our release this morning that we expect operating cost around $8 per BOE in 2017 higher than 2016 guidance as crude oil becomes a larger share of our production mix given its strong production growth next year. I’ll now turn it over to Eric to talk about the waterflood acquisition and the U.S.
basis differentials.
Eric Le Dain
Thanks, Ray. Subsequent to the third quarter, we entered into an agreement to acquire the anti-Creek asset for approximate $110 million net of closing adjustments.
Closing is expected in the fourth quarter. This is a low operating cost light oil producing asset where we see an ability to acquire our strong technical expertise and the secondary recovery in reservoir management to significantly increase recovery.
Anti-creek asset is one that we have identified some time ago after extensive screening internally have early stage waterflood opportunities in Western Canada and saw real potential here to acquire expertise. This is a continuation of our strategy of high grading our free cash flow generating waterflood portfolio, accretively selling limited growth, lower margin assets and adding or created higher working interest, higher margin assets with growth potential.
This acquisition is a great fit within this framework. We think of it is as a full time given that we have the ability to operationalize the asset within our existing resources.
We anticipate spending approximately $12 million on the Anti-creek asset in 2017 which will cover converting existing wells to injectors and sourcing additional water. At this time we do not see the need to drill any additional wells.
With much of the infrastructure already in place, we have seen opportunity to ramp up water injection and increase crude oil production by two to three times generating very strong economics. Alongside this acquisition, we continue to pursue our non-core divestment objectives.
As Ray mentioned we divested some small Canadian gas assets during the third quarter. We remain focused on continuing down this path.
I’ll just say a few words about realized pricing before turning the call over to Jodi. Our realized crude oil price improved modestly from Q2.
Improved differentials in the Bakken more than offset the slightly lower WTI price. Our Bakken differential averaged $639 per barrel below WTI.
We seen continued improvement in our Bakken differentials which has been driven by declining production in the Williston Basin leading to less real transport required to clear the basin. Strong local refinery demand has also supported the tighter differentials.
We see potentials for further improvements in our Bakken differential when the Dakota Access pipeline gets completed. Our realized natural gas price was meaningfully higher than Q2.
The key drivers were higher [Indiscernible] prices and higher pricing in the Marcellus. Although differentials in the Marcellus were wider than Q2, largely due to high regional storage inventories combined with normal seasonal weakness and demand and our realized third quarter Marcellus differential was a US$1.19 below NYMEX.
This compares to a Northeast Pennsylvania spot differential of around US$1.35 to US$1.40 per Mcf below NYMEX for the same period. Our realized differential was supported by a firm transportation agreement in the Marcellus that came into effect in August of this year.
This transport commitment is for 30 million cubic feet per day on the Tennessee gas pipeline which takes gas from our production region in Pennsylvania to the border of Kentucky and Tennessee where the line connects with many downstream alternatives achieving gas prices closer to Henry Hub. Realized prices for sales using this transportation were roughly $0.80 U.S.
and MMBtu higher than selling into the Pennsylvania spot market in August and September. In connection with this transport commitment our transportation costs have increased.
This is the primary reason we moved our transportation guidance in 2016 up to $3.15 per BOE from $3.10 previously. As we look ahead into 2017 we do expect higher transportation cost but these would be more than offset by the higher realized pricing.
Jodi will now review our ongoing cost improvements combined with additional actions taken to limit cost, commodity price volatility in 2017 will support the 2017 capital program outlined by Ian.
Jodi Jenson Labrie
Thanks, Eric. We have made considerable progress reducing cost across the business over the last 18 months.
This has been key to ensuring we can execute on our 2017 growth strategy at commodity prices in the US$45 to US$50 WTI range. We have lowered our operating cost guidance and G&A guidance every quarter in 2016 and as Ian mentioned our expectation is that we should realize approximately $80 million in savings for the full year when you add up operating transport and G&A cost compared to our original 2016 guidance.
Our third quarter cash operating cost are 25% lower on a yearly basis compared to the same period in 2015. We have realized operating cost savings across the board with some of the bigger cost of service wins coming from well servicing and repairs and maintenance.
This is partly due to our decision to shut in 600 yearly per day of Canadian gas production and not bring volumes back on when it did not make economic sense to do so. We expect these volumes to remain shut in for the fourth quarter.
In addition, our continued efforts to focus our portfolio and divest of non-core property has also helped lower overall operating cost during 2016. Our third quarter cash G&A cost are down 29% on a BOE basis compared to the third quarter of 2016.
We have continued to focus on cost saving effort and have reduced our staff levels by 35 % since the beginning of 2015. The impact divesting of non-core properties and focusing our portfolio has also impacted the level of G&A we require to manage our business.
It’s important to note that our focus on cost control will continue even as we begin to ramp up activity levels in 2017. We are conscious of the risk that both capital and operating cost may escalate as industry levels pick up.
As Ray mentioned, we have taken steps to protect our programs from cost escalation while still providing the opportunity to improve efficiencies and the flexibility to reduce activity levels if needed. Turning to hedging.
We have increased our crude oil hedge position to further protect our 2017 capital program and our recent Canadian waterflood acquisition. In addition to some fixed price swaps in the fourth quarter of 2016 at US$52 per barrel, we added fixed price swaps in 2017 at US$52.50 per barrel and additional three way collars at approximately US$39 by US$50 by US$61 per barrel.
We now have an average of 17,500 barrels per day hedged in 2017, predominantly through three way structures in order to retain some pricing upside. The volumes hedged are skewed to the second half of the year which is consistent with our 2017 production profile.
In addition, we have also begun to hedge crude oil for 2018 and 2019. For natural gas, we had increased our hedge protection 2017 to 50 million cubic feet per day using three way collars at [206] by US$2.75 and US$3.41 per 1000 cubic feet.
Our balance sheet remains strong with 75 million in cash and undrawn $800 million bank credit facility and $729 million of long-term senior notes outstanding at the end of the quarter. Our debt net of cash has decreased by 46% since the beginning of the year and we expect to realize annual savings and interest costs of approximately $20 million compared to 2015.
Subsequent to the quarter, we completed a one year extension of our $800 million bank credit facility which now matures October 31, 2019, with no changes to our terms or covenants. The decisive steps we have taken to increase our financial strength and cost and commodity price certainty, all while retaining flexibility has ensured that we are well positioned to execute on our growth strategy going forward.
I will now pass the call back to Ian for some closing comments.
Ian Dundas
Thanks, Jodi. Our third quarter results underline the progress we have made in positioning Enerplus to deliver profitable growth in a lower and potentially more volatile commodity price environment.
We have significantly strengthened our financial position, had continued success in increasing our margins through cost reductions, expect further margin expansion as we drive crude oil production growth in 2017 and continue to focus on improving capital and operational efficiencies. Until that, we will turn the call over to the operator and are available for your questions.
Operator
[Operator Instructions] Your first question comes from John Green from TD Securities. Your line is open.
John Green
Good morning, guys. Couple of quick questions here regarding the acquired Ante Creek asset.
First off, I believe you referenced two to three times growth over the current production level. Over what timeframe do you expect this growth?
The second one is how does this asset fit into the larger waterflood strategy? I believe the waterflood is in its infancy but it looks like quite a high current decline rates, so if you could just speak to that?
And last off, can you speak to why you choose to pursue this acquisition rather than accelerating spending in the Bakken, maybe going to a third rig sooner than you otherwise would have?
Ian Dundas
Sure. Yes, I will handle those.
So, I guess your first two questions, just to give you a little more color on that. We highlighted production of 3,800 BOE a days or 40% weighted oil volumes.
The flood, we don’t see it as in its infancy. It has started and so you really got to break the products apart.
Oil has effectively flattened out and so the volume we referenced, the upside was oil. This upside is all oil related.
So how we think that plays out sometime over the next year could be a little bit faster, could take a little longer. You are going to see the oil volume start to grow.
In that time period, you are going to see the gas come down a bit as gas circles back into solution and so quality here from now we are going to see the oil grow than we see two to three times upside on that. So, I guess the asset is going to decline a little but you are not going to see that relative to cash flow.
It’s all in connection with what we think is really modest spending. So, as you could imagine we see pretty powerful economics associated with that.
You also ask the question about maybe choices, capital allocation choices and why not three rigs in North Dakota. I’d highlight a couple things.
As we talk this morning, we see North Dakota production growing 25% from Q4 to Q4 under a two-rig program. It is significant, significant growth.
And so as we think about what we are trying to do operationally and what we are trying to do corporately in terms of re-establishing growth, really that level growth is really dramatic. We don’t need a third rig to get to the next level of growth.
So, sustainable growth we think is going to be very, very competitive and we didn’t have to make a choice here relative to capital allocation. We are able to do both, when we look at our financial position.
John Green
Okay. That’s great.
And just to clarify, you guys were speaking to $20 million in spending on the Ante Creek assets in 2017, is that right?
Ian Dundas
That would be a ’17, ’18 kind of thing. We only see spending $17 million next year -- sorry $12 million next year significantly under where we see cash flow from that asset.
John Green
Perfect. Perfect.
And lastly, I’d just take a shot in the dark here but have you guys disclosed the cash flow multiple or what the asset is currently producing in terms of cash flow?
Ian Dundas
We haven’t disclosed that but it is something about 3,000 BOE a day. Give it a $20 netback is not bad to think about and you see pretty attractive metrics over there.
John Green
Okay. Great.
Thank you very much, guys.
Ian Dundas
Thank you.
Operator
Your next question comes from Patrick O’Rourke from AltaCorp Capital. Your line is open.
Patrick O’Rourke
Good morning, guys. Just a few quick questions here.
First of all, you did talk about no minimums on the frac spread in the Bakken. Can you maybe talk about the contract structure for the first and second rigs and if those are contracted to minimums for the full year?
And then in terms of drilling program in the Bakken in 2017, how you see the cadence for drilling and production additions? Will you be doing a more aggressive pad structure with one rig for example and using the other for some of your science projects on the down spacing or how you are looking in that?
And then third and final, you left the fourth quarter guidance unchanged, so the acquired asset although it only produces for part of the quarter, is that considered in the 89,000 BOEs per day or would that be incremental?
Ian Dundas
I will answer the last one and then turn your first two questions over to Ray. So the 89,000 BOE a day exit number is unchanged from where we were and includes some partial contribution from the acquisition.
We highlighted in the call and in the script and in the release today, the fourth quarter was impacted by some curtailment in the Marcellus, some Canadian gas divestments and some Canadian gas curtailment. So, effectively 2,500 BOE a day, when you add all of that up that got impacted, offset in part by the strong well performance and the acquisitions.
So it’s all baked in together.
Ray Daniels
On -- sorry.
Ian Dundas
Is that good? All right.
I will turn to Ray for your first two questions on that.
Ray Daniels
Yes. On the rig contracts, we have two rigs contracted for next year.
One is contracted through till November and we have the option of cutting that on. And the other one is contracted to the middle of the year and we have a six month option on that.
So, we have the capability to reduce a drilling program if oil price dictates that. And as I mentioned on the call, our completions, we don’t have any big requirements on the completions and we can dial them down as we need to.
Patrick, what was your second question?
Patrick O’Rourke
Sorry, yes. Just in terms of the cadence how you look at drilling and bringing on production, will one rig be say more aggressive in pad drilling and some lumpy adds, and will the other rig maybe doing some science or how you are looking at that?
Ray Daniels
Yes. We still got some wells to drill to hold our leases.
So there will be one rig that’s focused on holding our leases and other rig will be doing the downspacing and density testing. And as I mentioned on the call as well, we will be doing different tests around spacing, proppant volumes and flow rates?
Patrick O’Rourke
Okay. Just one quick last question.
Still a lot of talk on testing different things, what inning -- I know it’s a stereotypical question but what inning do you kind of see yourselves on in terms of technological progress on the play right now?
Ian Dundas
So, you get, I do play baseball. So, after quarter four relative to rugby match.
Maybe let’s just move away from baseball. We have been public with our current density assumptions, which are grounded in a recovery factor and that recovery factors which our auditors have been supporting is 15%.
We talk today about encouragement in terms of what we’ve seen on this regional test. There is also a lot of other data out there and I would say by and large, it’s all sort of pointing in a direction of higher recovery factors.
So that’s a real positive thing. We have the luxury of not having to sort of make a firm commitment over there because we’ve got so much inventory that we are going to drill before we get to those downspace assumptions.
So, I don’t know we are part way through the game. We’ve got a lot of data.
We understand the oil in place and it’s really going to be a question of recovery factors and well results we get from that. But directionally, it’s pointing in a good direction.
Patrick O’Rourke
Okay. Thanks a lot, guys.
Operator
Your next question comes from Kurt Molnar from Raymond James. Your line is open.
Kurt Molnar
Good morning, guys. Ian, could you go into, if you are willing to go into a little bit more detail on the Ante Creek?
We see the appeal of the acquisition price. You’ve given a little bit of detail on cash flow versus capital required and clearly the asset has lots of existing infrastructure.
We’ve always seen the differentiating factor in your production growth in the Bakken being full cycle return on capital. Where is this going to rank on that kind of spectrum in your view if you’re willing to go into that kind of detail?
Ian Dundas
I guess we will see what detail if we get to when I finish this. Thank you for the question.
Strategically, Eric talked about this. This is bolt-on as it’s sort of part of portfolio optimization.
But our focus on everything we do is on, is squarely on full cycle returns. And so it’s really typically pretty hard to buy one of this kind of, we call it a successful waterflood asset and make reasonable money.
The low declines, stable reduction, the free cash flowing assets and they are always a very well bid in the market. And so we’ve been around those transactions over the years but generally has struggled to get even at low double-digit return.
So, we are never successful under those scenarios. It’s hard to make money and it hasn’t really been a focus area for us.
Now this deal is different. As Eric said, it has been sort of on our radar for a long time.
It screens very well. It’s also very interesting time for this asset.
So, a lot of money has been spent on it already. It’s suffered some pretty significant declines and now as we said oil, we think is effectively bottomed out.
It’s very interesting time for that asset. As I said, we see oil going up two to three times.
Initial response we think we will start to see within around a year. You model that up and you will see exceptional half cycle economics burdened with the purchase price and it lines up really well.
Let’s just call it strong double-digit returns and I guess you ask how it compares to the drilling program which is maybe one of the most fundamental questions. This lines up really well against our Fort Berthold drilling.
The key reason why we see this is -- it’s a pretty small little deal and we don’t want to spend too much time on it but it has exceptional returns and drives accretion at the corporate level.
Kurt Molnar
Thanks very much.
Ian Dundas
Thanks, Kurt.
Operator
[Operator Instructions] Your next question comes from Jason Frew from Credit Suisse. Your line is open.
Jason Frew
Hi, Ian. I think my question has been answered.
It was around how selective the Ante Creek asset was and how it fits into the broader portfolio. But I think you really did, already addressed that.
Ian Dundas
Great. Good luck with your election.
Operator
[Operator Instructions] Your next question comes from Ray Kwan from BMO Capital Markets. Your line is open.
Ray Kwan
Hey guys. Just following on the Ante Creek acquisition, sorry to beat the dead horse on that one.
But just wondering if you think this is a toehold into the area and do you see potential for expansion in the region there? That’s it.
Ian Dundas
This is what this is. It comes with a fair amount of acreage but that’s not at all the focus for us.
This is a highly focused waterflood asset. It is no more than that.
It is self-contained business.
Operator
[Operator Instructions] We do not have any questions at this time. I will turn the call over to the presenters.
Ian Dundas
Well, thank you very much for your time. Again, apologize for the technical delay.
Hope everyone has a great day. Thank you.
Cheers.
Operator
That concludes today’s conference call. You may now disconnect.