Enerplus Resources Fund (ERF) Q4 2020 Earnings Call Transcript

Image source: The Motley Fool.

Enerplus Resources Fund (ERF 0.59%)
Q4 2020 Earnings Call
Feb 19, 2021, 11:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Good morning, ladies and gentlemen, and welcome to the Enerplus Corporation Q4 and year-end 2020 results conference call. [Operator instructions] This call is being recorded on February 19, 2021.  I would now like to turn the conference over to Mr.  Drew Mair. Please go ahead. 

Drew Mair

Thank you, operator, and good morning, everyone. Thank you for joining the call. Before we get started, please take note of the advisories located at the end of today's news release. Our financials have been 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; Jodi Jenson Labrie, senior VP and chief financial officer; Wade Hutchings, senior VP and chief operating officer; Shaina Morihira, VP, finance; and Garth Doll, VP, marketing. Following our discussion, we will open up the call for questions.  With that, I will turn it over to Ian. 

Ian Dundas

Well, thank you, Drew. Good morning, everybody. To our friends in the US who are dealing with some rough weather, I hope everyone is safe and warm. Thank you for joining us today.  This morning, we announced our fourth quarter and full-year 2020 results, and I'll start by describing some of the highlights from last year before talking about our plans for 2021 and the Bruin acquisition.  Clearly, 2020 was a complicated and challenging year, and I want to thank our staff and our strategic partners for all of their support and dedication.

Their commitment to ensuring safe, reliable operations in the face of the pandemic has been nothing short of exceptional.  One of the most important takeaways in 2020 was that we were able to maintain our financial strength and preserve shareholder value, while turning the challenges of 2020 into an opportunity to emerge as an even stronger, better positioned company. We did this by taking action to adopt to sharply lower commodity prices, including adjusting our operational plans and maintaining focus on reducing our cost structures, while continuing to deliver strong operational performance, solid financial results and continued ESG improvements.  As a result, we entered 2021 in a position to execute on the Bruin opportunity. Operationally, the Bruin assets fit well, all in the Bakken with a material position in the Fort Berthold area directly adjacent to our acreage.  We're able to acquire the company at a valuation that we believe was attractive, both on an absolute and a relative basis and underpinned by Bruin's existing production. The transaction will be immediately accretive to shareholders with robust accretion to adjusted funds flow per share and free cash flow per share.

We highlight that we expect the pro forma business to generate more than $300 million in free cash flow this year based on a 10-month contribution from Bruin and assuming $55 West Texas oil and $3 NYMEX natural gas prices.  It was also important to us that we financed the acquisition appropriately, ensuring that we remain in a position of strength with a solid balance sheet and excellent liquidity. We expect it to be undrawn on our USD 600 million bank facility when the transaction closes in early March. And if current pricing holds, we anticipate taking our balance sheet to approximately one times by year end.  The Bruin acquisition comes with 24,000 BOE a day -- per day of current production, 10 net drilled uncompleted wells and about 100 net drilling core locations. We also see potential upside beyond these locations, and Wade will speak more about the inventory and upside in his remarks.  We do expect to realize tangible synergies with the acquisition.

We are not adding any G&A. And there will be clear benefits from running a larger, more efficient capital and operating plan. We plan to report out on these efficiencies as we begin to realize them. Our pro forma 2021 capital budget remains between 335 to $385 million, which reflects a maintenance capital plan.  We are committed to a plan which generates free cash flow, which we are well positioned to deliver following the Bruin acquisition and with the improving commodity price environment.

First call on that free cash flow will be balance sheet. We are also focused on opportunities to provide incremental return of capital to shareholders beyond our current dividend as we make progress on our balance sheet objectives.  Lastly, I'll wrap up with a few ESG comments. We've made strong progress further integrating and enhancing our ESG strategies into our business and delivering on our targets over the last 12 months. In 2020, we exceeded both our emissions intensity and freshwater use reduction targets, and we delivered the best safety performance in our company's history.

These, along with our other ESG initiatives, will continue to be priorities in 2021, and we believe this focus will create value for our stakeholders. Our board is deeply engaged on this topic, and we're committed to continuing to pursue excellence here.  Now, I will turn the call over to Wade. 

Wade Hutchings -- Senior Vice President and Chief Operating Officer

Thanks, Ian, and good morning, everyone.  Like other producers, our 2020 capital and operating plan changed dramatically from our initial expectations. But despite all the changes, it was a solid year from an operational perspective. Our execution started strong. And by the time we suspended our D&C activity in April, we had achieved record performance for our company in terms of drilling and completion cycle times, which translated into significant capital efficiency improvements.

As we reinitiated some capital activity in the fourth quarter, completing four previously drilled wells, we were able to further improve upon our completion efficiency, with our last pad averaging 15 stages per day. On average, in 2020, we were able to reduce our total well cost in the Bakken to USD 6.3 million, which represents a USD 1.3 million per well improvement year over year.  Turning to 2021, we expect to keep this operational momentum going and believe we can continue to improve this well cost performance. We plan to provide more detailed guidance once the Bruin acquisition closes, but the pro forma budget that we've outlined assumes that we layer in Bruin's 10 net drilled uncompleted well inventory into our completions program this year. We are on track to commence completion activity in North Dakota at the start of March and also plan to reinitiate drilling activity there starting in the spring with one rig.  Another area we are focused on is restoring production from a subset of Bruin's wells, which require workovers.

Many of these wells were shut in during the low oil price environment last summer or simply went down in the normal course. And with current pricing providing robust workover economics, we will be accelerating their return to production.  As Ian noted, we have identified about 100 net drilling locations across Bruin's Fort Berthold and Williams acreage. As we think about upside to this number, it primarily relates to the Williams acreage. For context, the Williams locations we've identified are only focused on the eastern portion of their land position or about one-third of their Williams acreage.

These locations are also predominantly Middle Bakken-focused with less development envisioned in the Three Forks.  As you move further west in Williams County, the hydrocarbon system degrades, and the wells aren't as productive. So today, we're not including that Western Williams land in our forward plans or drilling inventory. But if we have continued success reducing well costs, potentially also supported by higher commodity prices, there could be a time when we'd revisit that acreage for development.  I would note that the Williams acreage does offer the potential for lower cost structures than Fort Berthold given the shallower nature of the reservoir and lower ancillary costs due to being off the reservation.  Further to Ian's comments on synergies, while the Bruin acquisition doesn't dramatically increase our scale, it will support a more efficient capital and operating plan. Rather than laying down our drilling rig later in the year, we'll likely keep it operating.  We'll also bring more wells on production with our frac partner, allowing us to maintain momentum and help drive costs lower.

We also expect to see benefits to operating costs for the combined operations, and we will report out on these as we make progress.  Turning to our year-end reserves. With the reduced levels of capital activity, 2020 was not a year where we saw significant reserve additions. Notwithstanding this, our overall performance was on track. Excluding economic revisions due to the reduced-price forecast, we replaced 89% of production corporately and 119% of production in North Dakota on a proved plus probable basis.

Our F&D numbers were quite strong, supported by the success we've had reducing our well costs. Our proved F&D was $6.78 per BOE -- or excuse me, CAD 6.7 per BOE and proved plus probable F&D was $6.50 per BOE. I'll leave it there and pass the call to Jodi. 

Jodi Labrie -- Senior Vice President and Chief Financial Officer

Thanks, Wade. The combination of quickly reducing capital activity and our considerable success driving cost savings, generated free cash flow in 2020 despite the low oil price environment for most of the year. Our adjusted funds flow for 2020 was $358 million, which fully funded our capital spending requirements and generated $67 million of free cash flow. In the fourth quarter, we recognized a $311 million non-cash property plant and equipment impairment due to the lower commodity price environment and the use of constant 12-month trailing prices to test for impairment in accordance with the Securities and Exchange Commission requirements.

This impacted our earnings, leading to a fourth-quarter net loss of $204 million.  Moving on to our oil realizations in the Bakken. Our differential averaged USD 4.82 per barrel below WTI in the fourth quarter. Our full-year Bakken differential averaged just under USD 5 per barrel. With the decline of in-basin production in the Bakken during 2020 and more stability in oil prices, we're seeing a more constructive market for Bakken crude, with current spot differentials trading tighter than USD 3 per barrel below WTI.

This strength is supporting our 2021 differential guidance of USD 3.25 per barrel, which assumes the Dakota access pipeline continues to operate.  Turning to the Marcellus. Regional natural gas prices were particularly weak between September through November in 2020 due to nearly full regional storage combined with low demand due to mild weather. As a result, our realized Marcellus sales price differential widened to over USD 1 per Mcf below NYMEX during the fourth quarter, driving our full-year 2020 Marcellus differential to $0.65 per Mcf below NYMEX. We expect our average 2021 Marcellus differential to improve to $0.55 per Mcf below NYMEX.

This is an annual average estimate and includes normal seasonality where we expect robust pricing and differentials during the winter months with more moderate pricing and differentials during the warmer months.  Moving on to the balance sheet. We ended the year in a strong position with significant liquidity, consisting of $114 million of cash on hand and USD 600 million of undrawn capacity on our bank credit facility. Subsequent to year-end, and in connection with the Bruin acquisition, we raised $132 million in gross proceeds from our equity offering and entered into a new three-year senior unsecured USD 400 million term facility to be fully drawn down on the closing date of the acquisition. This term facility includes financial and other covenants, along with pricing consistent with our existing credit facility.

If current pricing holds, we expect to take our net debt to adjusted funds flow ratio to approximately one times by year end, in line with our long-term leverage target.  Lastly, we have added to our commodity hedging position. We now have approximately 21,500 barrels per day hedged in 2021, primarily through three-way collars at average WTI prices of approximately USD 34.50 by USD 44 by USD 54 per barrel. As we previously disclosed, upon closing of the Bruin acquisition, we will assume their hedge positions and record them on our balance sheet at fair value as part of the purchase price.  In 2021, Bruin has 9,000 barrels per day swapped at USD 42 WTI. The realized and unrealized gains and losses on the Bruin hedges will be recorded in our financial statements on a go-forward basis, which will reflect the changes in WTI prices from the date of close.  I'll leave it there, and we'll turn the call over to the operator and open it up for questions. 

Questions & Answers:

Operator

[Operator instructions] The first question comes from Patrick O'Rourke with ATB Capital. Please go ahead. 

Patrick ORourke

Oh, hey, guys. Good morning. Just a couple of quick questions on the nuance of the reserve report. I know there was a little bit of a technical revision there.  It looks like maybe perhaps some barrels shifted from 2P into 1P as is normal.

But I'm wondering, with regard to the rest of the technical revision, what the driver was there. I know about 183 million came out of FDC. Is that wells coming out of the reserve report? Or is that FDC reduction being more driven by the well cost improvements that you've made and those being seen as structural?

Ian Dundas -- President and Chief Executive Officer

Wade, do you want to handle that?

Wade Hutchings -- Senior Vice President and Chief Operating Officer

Sure. Patrick, thanks for the questions. On the FDC question, by far, the biggest driver of those FDC changes are lower forward well cost projections given the success we've had over the last year in reducing those costs. As you saw in the release, we reduced cost year over year by 17%, USD 1.3 million.

And so, as you bake that in the long term, FDC, it ends up making a pretty big impact.  I think to go back to your point on probable tech revisions, really, the key driver that you're seeing there is as our confidence grows in our 1P assignment, what you see is shifts from reserves from probable into proved. And so, even though the overall 2P number doesn't change, that probable number does change. It actually shows a negative even though the total hasn't changed.

Patrick ORourke

OK. Great. And then, just a quick question. I know Jodi talked -- address the Bruin hedge book.

My assumption would be that you came into that with eyes wide open and priced that into the deal. I'm just curious on potentially the longer and more absurd end of their hedge book on the five by 75 collar. If you guys see any need to have that sort of protection in 2023, or if you would think about unwinding that to maybe preserve potential upside beyond $75.

Ian Dundas -- President and Chief Executive Officer

Patrick, so of course, none of that was news, and it was all disclosed in the initial acquisition announcement when we sort of talked about the pro forma hedge book.  As to that little strange collar you're talking about, let's just -- I put that in the bucket of immaterial. There were some nuances that the company had -- that company had to put it on as they emerge from bankruptcy. And so, yes, we'll think about that one in isolation. But if we're dealing with the $75 cap as a problem, I'll call it a quality problem, to be dealing with.  But I think if you step back and think about that hedge book we have, we're pretty comfortable.

It's given us really meaningful downside protection, and then we've structured it to preserve pretty significant upside through the unhedged volumes, obviously, and then the three-ways that we've been using. And then, obviously, as we move on to 2022, the hedge book is even more modest again.

Patrick ORourke

Yeah, yeah, very fair. I think if anybody needs a $5 put through for a full year, I might need to look for a new job at some point here. But thank you for that. 

Ian Dundas -- President and Chief Executive Officer

OK. Thank you. 

Operator

Thank you. We have a following question from Greg with RBC Capital Markets. Please go ahead. 

Greg Pardy -- RBC Capital Markets -- Analyst

Yeah, thanks. Good morning. Just a couple. Maybe just to go back to the reserve report a little bit and just well performance and so forth.

So obviously, I mean, Wade, you mentioned reserve replacement really a function of spending levels, obviously, over the course of last year. Could you maybe just comment on well performance? I know the costs are continuing to go in the right direction. But any thoughts there would be helpful. 

Wade Hutchings -- Senior Vice President and Chief Operating Officer

Sure. Happy to address that, Greg. At a high level, I would say, well performance continues to track our expectations. To dive a little bit more into those reserve replacement numbers in North Dakota, the 69% reserve replacement does move up to 119% if you take out the price-driven economic revisions.

And the key drivers overall for our reserve replacement in 2020 in North Dakota, really, are a product of a bit of lower capital investment in 2020, obviously. But then also appreciate that our long-range plans have shifted to a bit of a lower growth model than we may have previously had. And so, that also impacts the number of new 2P reserves you can add into the system. It was not driven at all by well performance.

As I noted, the results from the last couple of years, and specifically, even the 2020 results, have tracked right close to our type curves. 

Greg Pardy -- RBC Capital Markets -- Analyst

OK. Terrific. And maybe to go up now to 15, 20,000 feet. I realize Bruin's closing in March, but your balance sheet, I mean, remains best-in-class, and you guys are very careful in how you go about doing things.

But I guess a question for Ian, is now that you've got increased scale and increased free cash flow and so forth, are there further consolidation acquisition opportunities that you would see either in the Bakken or the Permian, or would you actually even include Canada in that mix? So I know that's a granular question, but I'm just trying to get my head around how you're thinking about the business going forward. 

Ian Dundas -- President and Chief Executive Officer

Greg, I might sound a bit redundant here. We're just executing, or we've just executed on a transaction that I think makes a lot of sense to us. And we've had some positive feedback. We're just continuing to consolidate in our main area of focus.

So would we continue to do those sorts of things if valuation lined up? Clearly, that could be pretty smart business. And so, yeah, there's other opportunities out there. We are not the big dog in that basin. We don't have a dominant position.

So we see opportunity there. I guess, we'll see how that market unfolds. We've only had two cash transactions in North Dakota in the last couple of years, really. So we'll see if this is the start of a trend.  And to your comment about balance sheet, it was really important to us to maintain that balance sheet strength, which is one of the reasons we put a bit of equity out the door for all of the strategic benefits that can come from having a strong balance sheet, including the ability to continue to look for opportunistic acquisition opportunities.  The other part of your question, how would we think about things outside of North Dakota? I think we've been consistent.

We view the core of the company as being North Dakota and building around that makes sense. Are there other opportunities out there? Yeah, I think you have to keep your eyes open to other opportunities. Whenever you're starting to speculate on that, people's ears perk up and wonder what it looks like. So I don't know what it looks like because right now, we're talking about Bakken consolidations.

But someday, perhaps, we do pay attention to North America carefully. Again, most of the things that we see are in the US, which is where most of our focus is, but there are some interesting opportunities in Canada as well.  But again, I come back to what the focus area today largely is in our backyard, and we see opportunities there, and including the where we just executed on. Happy to add more, if you want more color on that. 

Greg Pardy -- RBC Capital Markets -- Analyst

No, I think that does it. Yeah. Thanks 

Ian Dundas -- President and Chief Executive Officer

Thanks, Greg. 

Operator

Thank you. [Operator instructions] There are no future questions at this time. You may proceed. 

Ian Dundas -- President and Chief Executive Officer

Alright. So we'll leave it there. Thank you for everyone joining us on this Friday morning, and have a good, safe weekend. Take care.

Cheers. Bye.

Duration: 25 minutes

Call participants:

Drew Mair

Ian Dundas -- President and Chief Executive Officer

Wade Hutchings -- Senior Vice President and Chief Operating Officer

Jodi Labrie -- Senior Vice President and Chief Financial Officer

Patrick ORourke

Greg Pardy -- RBC Capital Markets -- Analyst

More ERF analysis

All earnings call transcripts