Enerplus Corp (ERF) 2016 Q3 法說會逐字稿

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 third-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. Thanks for joining us. Apology for the delay on the call this morning. We had some technical issues but we'll try 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 relative to this discussion. Our financials have prepared in accordance with US 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'm here this morning with Ian Dundas, our President and Chief Executive Officer; Ray Daniels, Senior Vice President, Operations; Eric Le Dain, Senior Vice President, Corporate Development and 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.

Good morning, everyone. We appreciate your attendance this morning. Again, apologize 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 CAD80 million less than our original 2016 guidance and approximately CAD115 million less than we spent in 2015. Our Q4-to-Q4 capital efficiency for 2016 is expected to be in the 16,000 per flowing barrel range while spending 90% targeting oil development. We have significantly strengthen our financial position, with net debt down 46% since year end 2015. In short, we remain on track to reinitiate profitable and sustainable growth in 2017.

Our preliminary outlook for 2017 capital spending is CAD400 million, an increase from this year's CAD215 million budget. The majority of the increase in spending will be allocated to North Dakota, where we have a second operated drilling rig starting in January. 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 $50 per barrel for West Texas and $3 per MCF to NYMEX. We expect to produce 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 Bakken is a key priority for our drilling program and could have positive implications for our inventory. Ray will speak more about this.

A critical element of our strategic plan has been to our 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 is highly creative and we believe the asset will generate exceptional returns. In parallel with this acquisition, we continue to pursue our non-core divestment objectives.

With that, I will turn the call over to Ray, who will provide some of our operational highlights.

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 on Q4 production from this curtailment to be approximately 1,500 barrels of oil equivalent per day. However, in recent weeks cash prices in the Marcellus have improved considerably and the curtailed production is now back online.

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 a return. We also divested some minor non-core gas production during the quarter. Combined, the Canadian gas shut-ins and (technical difficulty) about 1,000 barrels of oil equivalent per day. Notwithstanding these losses to 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 will talk about our objectives for this asset as we move to a larger program in 2017. Firstly, we plan to reestablish 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 a 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've made in drilling, where we have reduced cycle times by over 20% relative to our 2015 average. Our pace-setter well this year with drilled 40% faster than our 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 plan.

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 test in 2017 with varying inter-well spacing. For context, our current spacing pattern assumes 1,400 feet with approximately four wells in the middle 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, cluster spacing and proppant volumes, all in service of improving our capital efficiency. Although we are planning for increased activity, I would 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 minimum contractual commitment and can therefore very quickly dial back completion activity if we choose.

Moving on briefly to our Canadian operations on the Marcellus, in Canada activity has been largely focus 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 costs around CAD8 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 will now turn it over to Eric to talk about the waterflood acquisition and the US-basis differentials.

Subsequent to the third quarter, we entered into an agreement to acquire the Ante Creek asset for approximate CAD110 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 apply our strong technical expertise and secondary recovery in reservoir management to significant increase recovery.

The Ante Creek asset is one that we had identified some time ago, after extensive screening internally of early-stage waterflood opportunities in Western Canada and saw a real potential here to acquire our 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 operated higher working interest, higher margin assets with growth potential. This acquisition is a great fit within this framework. We think of it as a bolt-on, given that we have the ability to operationalize the asset within our existing resources.

We anticipate spending approximately CAD12 million on the Ante Creek asset in 2017, which would 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 see an 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 realize pricing before turning the call over to Jodi. Our realize crude oil price improve modestly from Q2. Improved differentials in the Bakken more than offset the slightly lower WTI pricing.

Our Bakken differential averaged $6.39 per barrel below WTI. We've see continued improvement in our Bakken differentials, which is being driven by declining production in the Williston Basin, leading to less rail transport required to clear the basin. Strong local refinery demand has also supported the tighter differentials. We see potential for further improvement in our Bakken differential when the Dakota Access Pipeline gets completed.

Our realized natural gas price was meaningfully higher in Q2. The key drivers were higher [ACKO] 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 in demand. Our realize third-quarter Marcellus differential was a $1.19 per MCF below NYMEX. This compares to our Northeast Pennsylvania spot differential of around $1.35 to $1.40 per MCF below NYMEX 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 guess 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 per sales using this transportation were roughly $0.80 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 CAD3.15 per BOE from CAD3.10 previously. As we look ahead into 2017, we do expect higher transportation costs, but these would be more than offset by the higher realize pricing.

Jodi will now review our ongoing cost improvements, combined with additional actions taken to limit costs and commodity price volatility in 2017 that will support the 2017 capital program outlined by Ian.

Thanks, Eric. We have made considerable progress reducing costs 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 $45 to $50 WTI range. We have lowered our operating costs guidance and G&A guidance every quarter in 2016 and as Ian mentioned, our expectation is that we should realize approximately CAD80 million in savings for the full year, when you add up operating, transport and G&A costs compared to our original 2016 guidance.

Our third-quarter cash operating costs are 25% lower on a BOE basis compared to the same period in 2015. We have realize 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 BOE 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 while also help lower overall operating costs during 2016.

Our third-quarter cash G&A costs are down 29% on a BOE basis compared to the third quarter of 2015. We have continued to focus on cost saving efforts and have reduced our staff levels by 35% since the beginning of 2015.

The impact of 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 costs may escalate as industry levels pick up. As Ray mentioned, we have taking steps to protect our progress 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 $52 per barrel, we added fixed price swaps in 2017 at $52.50 per barrel and additional three-way collars at approximately [39] by $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've also begun to hedge crude oil for 2018 and 2019. For natural gas, we have increased our hedge protection 2017 to 50 million cubic feet per day using three-way collars at [206] by $2.75 and $3.41 per thousand cubic feet.

Our balance sheet remains strong, with CAD75 million in cash, an undrawn CAD800 million dollar bank credit facility and CAD729 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 approximate CAD20 million compared to 2015.

Subsequent to the quarter, we completed a one-year extension of our CAD800 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.

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.

With that, we will turn the call over to the operator and are available for your questions.

(Operator Instructions)

John Green, TD Securities.

Good morning, guys. Couple quick questions here regarding the acquired Ante Creek assets.

First off, I believe you referenced 2 to 3 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 currency [climb] rate so if you could just speak to that.

Last off, can you speak to why you chose to pursue this acquisition rather than accelerating spending in the Bakken, maybe going to a third rig sooner than you otherwise would have?

Sure. I'll handle those. I guess your first two questions -- to give you a little more color on that. We highlighted production of 3,800 BOE a day, or 40 percentage weighted to oil volumes.

The flood, we don't see it in its infancy. It has started. You really got to break the products apart.

Oil is effectively flattened out, and so the volume we referenced, the upside was oil. This upside is all oil related. How we think that plays out, sometime over the next year, could be a little bit faster, could take a little bit longer, you're going to see the oil volume start to grow.

In that time period, you can see the gas come down a bit as gas circles back into solution. Call it year from now, we're going to start see the oil growth and see two to three signs upside on that. I guess the asset is going to decline a little, but you're 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 can imagine, we see pretty powerful economics associated with that.

You also asked the question about choices, capital allocation choices and why not three rigs in North Dakota? I would highlight a couple of things.

As we talked this morning, we see North Dakota production growing 25% from Q4 to Q4 under a two-way program. It is significant, significant growth.

As we think about what we're trying to do operationally and what we're trying to do corporately in terms of reestablishing growth, 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 that will be very, very competitive, and we didn't have to make a choice here relative to capital allocation, we were able to do both when we look at our financial position.

Okay, that's great. Just to clarify, you guys were speaking to CAD20 million in spending in the Ante Creek assets in 2017, is that right?

That would be 2017, 2018 kind of thing. We really only see spending CAD17 million next year -- sorry, CAD12 million next year, significantly under where we see cash flow from that asset.

Perfect. Lastly, just take a shot in the dark here, but have you guys disclosed the cash flow multiple are with the asset is currently producing in terms of cash flow?

We haven't disclosed that, but use something above 3,000 BOE a day, give it a CAD20 net back, is not bad to think about. You see pretty attractive metrics out of that.

Okay, great. Thank you very much, guys.

Patrick O'Rourke, AltaCorp Capital.

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?

Then in terms of drilling program in the Bakken in 2017, how do 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're looking in that?

Third and finally, you left the fourth-quarter guidance unchanged. 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?

I will answer the last one and then turn your first two questions over to Ray. 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 -- sorry, 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. Effectively 2,500 BOE a day when you at all of that up that got impacted, offset in part by the strong well performance and the acquisition. It's all baked in together.

I will turn to Ray for your first two questions.

On the rig contracts, we have two rigs contracted for next year. One is contracted through till November and we have the option of carrying that on. The other one is contracted to the middle of the year, and we have a six-month option on that.

We have the capability to reduce our drilling program if oil price dictates that. As I mentioned on the call, our completions -- we don't have any take requirements on the completions, and we can dial them down as we need to.

Patrick, what was your second question?

Sorry. 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 add? Will the other rig be maybe doing some science or how you're looking at that?

Yes, we've still got some wells to drill to hold our leases, so there will be one rig that is focused on holding our leases and the other rig will be doing the down spacing and density testing, yes. As I mentioned on the call as well, we will be doing different tests around spacing, proppant volumes and flow rates.

Okay. Just one quick last question, then. 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 ourselves on in terms of technological progress on the play right now?

I don't play baseball. Is there a quarter four relative to rugby match? 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 factor, which are auditors have been supporting, is 15%. We talked today about encouragement in terms of what we've seen on this original test. There's also a lot of other data out there.

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 make a firm commitment over there because we've got so much inventory that we're going drill it before we get to those down space assumptions.

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 going to be a question of recovery factor and the kind of well results we get from that, but directionally it's pointing in a good direction.

Okay. Thanks a lot, guys.

Kurt Molnar, Raymond James.

Good morning, guys. Ian, could you go into -- if you're 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?

I guess we'll see what detail we get to when I finish this. Thank you for the question, though.

Strategically, Eric talked about this. This is bolt-on-esque. It's part of portfolio optimization. The focus, our focus on everything we do is done squarely on full cycle returns, and so it's really typically pretty hard to buy one of these, we call it, a successful waterflood asset and make reasonable money.

They're low decline, stable production, they're free cash flowing assets, and they are always very well fit in the market and so we've been around those transactions over the years, but generally you struggle to get even 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.

This deal is different. As Eric said, it has been on our radar for a long time. It screens very well. Is also very interesting time for this asset.

A lot of money has been spent on it already. It suffered some pretty significant declines and now, as we said, oil we think is effectively bottomed out, so it's a very interesting time for that asset.

As I said, we see oil going up 2 to 3 times. With its initial response, we think we will start to see within around the year. You model that up and you will see exceptional half-cycle economics.

Burden it with the purchase price and it lines up really well. Let's just call it strong, strong double-digit returns. I guess you asked 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 as -- it is 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.

Thanks very much.

Thanks.

(Operator Instructions)

Jason Frew, Credit Suisse.

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 address that.

Great.

(Operator Instructions)

Ray Kwan, BMO Capital Markets.

Hey, guys. Just following on, on the Ante Creek acquisition. Sorry to beat a 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.

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 a self-contained business.

(Operator Instructions)

We do not have any questions at this time. I will turn the call over to the presenters.

Thank you very much for your time. Again, apologize for the technical delays. Hope everyone has a great day. Thank you. Cheers

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