Obsidian Energy Ltd (OBE) 2017 Q3 法說會逐字稿

Good morning. My name is Jessa, and I will be your conference operator today. At this time, I would like to welcome everyone to the Obsidian Energy's Third Quarter Results Conference Call.

(Operator Instructions) Thank you.

Mr. Brad Monaco, Manager of Corporate Planning and Investor Relations, you may begin your conference.

Good morning, everyone. Thank you for joining us.

This morning, we will be discussing our strong third quarter 2017 results and details around our 2018 budget. The format of this call will be audio only.

With me this morning and speaking on the call is Dave French, President and Chief Executive Officer; David Hendry, Chief Financial Officer; and Tony Berthelet, Vice President, Development and Operations. The rest of the leadership team is also in attendance.

Before I turn the call over to Dave, I'd like to point out that we will refer to forward-looking information in connection with Obsidian Energy and the subject matter of today's call. By its nature, this information contains forecasts, assumptions and expectations about future outcomes, so we'll remind you they're subject to the risks and uncertainties affecting every business, including ours. Please refer to our public disclosure filings available on both SEDAR and EDGAR systems for a full discussion of significant factors and risks that could affect Obsidian Energy or could affect future outcomes for Obsidian Energy.

Go ahead, Dave.

Good morning, and thank you all for joining us.

I'd like to start the call by saying how pleased I am to share our third quarter results today. We have been relatively quiet externally over the last several months, but I think this release gives you some idea that inside we were rolling along. We put together great results across every facet of the business, and this is a true testament to the Obsidian Energy team.

One of the things we've been most looking forward to talking about is our first foray into our Deep Basin position. Early indications from our 3-well Mannville program are very strong. The wells are liquids rich and flowing strong on choke. We're holding back the gas rates on these wells to manage pressure and hydrates but more importantly to get the most high-value liquids as possible. Our 3 wells are producing approximately 60 barrels per million, a result that meaningfully improves already attractive economics.

Our successful Q3 drilling program did not stop there. We are meeting or beating expectations across all key development areas. Our base performance in new well delivery gives us confidence to forecast production on the high end of guidance. Keep in mind we lowered our total capital guidance by $20 million this past quarter. Tony will expand on these results later in the call. Our full year production is as strong as it is because of our shallow [waterflooded times], and this keeps getting better. The investments we have made since the third quarter of last year are starting to bear fruit. We are happy to highlight the powerful results seen to date. In our entire Cardium position this year, decline is extremely shallow at 5%. This asset is a powerful foundation for cash with high margins, low production runoff, good capital efficiency and strong liquids weighting that keeps us nicely able to participate in the current commodity strengthening.

That brings me to our 2018 plans. We are leaning into a shorter-cycle inventory in our portfolio next year, with lower costs, integrated waterflood and decline mitigation still very much a priority. In 2018, we conservatively plan to deliver 5% production growth while investing only 80% of funds flow from operations at strip pricing. This scalable budget leaves us room to draw on the deep inventory of drill-ready projects to expand development in the second half of the year should strong pricing continue.

Our Board of Directors approved a well-structured and [togglable] 2018 budget of $135 million, with half of the development capital heading to the Cardium and the rest split between other development areas. In the Cardium, we plan to blend our integrated type 4 and type 1 waterflood approaches to be short cycle focused, mainly by not drilling new injectors and just converting existing producers. This reduces capital demand and still gives us a good producer-to-injector pattern management. We will also drill some primary Willesden Green wells in some of our halo acreage and expect an excellent rate profile from the mix of projects.

Our third quarter results demonstrate our ability to deliver both base production management and predictable liquids-weighted growth. This was a stand-and-deliver quarter for Obsidian Energy and, frankly, a genuine pleasure to talk about. We are excited about the momentum in the business, and as is usually the case, good operational performance translates well into solid financial performance.

With that, I will turn the call over to Dave Hendry to discuss our third quarter financial highlights.

Thank you, Dave.

Funds flow from operations for the third quarter was $40 million or $0.08 per share. This is a 25% increase from Q3 2016 due to higher commodity prices and lower operating and G&A costs which more than offset a smaller production base. We are slightly down from Q2 2017 due to the strengthening Canadian-U. S. dollar exchange rate.

Third quarter operating costs were $12.26 per boe, net of our Peace River carry, as compared to $14.27 per boe in Q2. As expected, operating costs were lower in the second quarter of 2017 due to a reduction of repair and maintenance spend. We continue to target annual 2017 operating costs of approximately $13 to $13.50 per boe, net of our carried expense. As a reminder, we forecast our Peace River carry to expire by the end of this year. $55 million of capital expenditures were invested across the business in the quarter, and we remain on track to meet full year 2017 capital guidance.

Our cash margins continued to be solid with netbacks of $18.70 per boe in the third quarter compared to $19.96 in Q2, with the difference being a decline in commodity prices which was partially offset by improved operating costs.

Average liquids sales prices were $45.05 per boe, and average natural gas sales prices were $2.35 per mcf in the quarter. Realized natural gas prices were at a premium to AECO on the quarter, as a portion of our gas volumes is marketed at alternative sale points. We expect our gas realizations to maintain a slight premium to AECO through 2018.

Total net debt was $410 million at the end of the third quarter, including $251 million drawn on our $410 million revolving credit facility and $113 million of senior notes. We had a larger working capital deficit in the quarter resulting from the timing of payables related to our Q3 capital program.

Commodity risk management gains of $2.24 per boe were realized in the quarter, driven by our strong crude oil and natural gas hedging position. We expanded our hedge book this month to take advantage of an attractive crude price that supports our 2018 capital program and began to expand our hedge book into mid-2019. We now have approximately 2/3 of our liquids portfolio hedged for 2018, putting us in a position to better withstand commodity price volatility and manage our ongoing capital programs. We also took advantage of the October decline in the Canadian dollar relative to the U.S. dollar and hedged approximately 2/3 of our foreign exchange exposure on our 2018 U.S. dollar WTI hedges.

On the disposition front, we entered into agreement to sell our Alberta Viking royalties for $40 million. At over $200,000 per flowing barrel and 15x NOI, this transaction creates meaningful value for all stakeholders. Proceeds will be used to pay down debt and is neutral to 2018 funds flow from operations. Closing is anticipated for later this month.

I will now pass the call to Tony Berthelet to take everyone through our busy operational third quarter.

Thanks, Dave.

It was a truly exciting quarter for our company. We executed all development activities on time and on budget, and our Q4 is also shaping up well. Our Q3 development activity is built on a platform with low-decline base production in our waterflood-supported Cardium acreage. Base decline in the Cardium has shallowed to 5% year-to-date as a result of our waterflood and base optimization projects that began in the third quarter of 2016. I can't overemphasize how important this is for our future growth profile of Obsidian Energy. The dollars we committed to putting water in the ground are delivering the expected results we have discussed over the last few quarters.

In Pembina Cardium Unit #9, we brought 3 horizontal producers on production subsequent to the quarter, and early-read indications are exceeding type curve expectations. We are currently drilling our 4 horizontal wells in Willesden Green and expect the pads to turn over to production prior to year-end. Both programs are developed using integrated waterflood support, and we expect decline rates lower than typical primary wells.

In the Alberta Viking, our 10-well program continues to perform above budget. All 10 wells are on production, including the 100/2-18 well, which had a peak initial rate of 704 boe per day and a producing IP30 rate of 295 boe per day. We continued to evolve our development strategy in the area to enhance overall economics, including trucking clean oil through design change in our multi-well batteries and optimizing stage count to maximize capital efficiency.

Our second half 2017 Peace River program returned to the heart of Harmon Valley South field, and preliminary results of the program are encouraging. Daily total production from the first 9 wells of the H2 program is currently 1,700 boe per day or approximately 190 boa -- boe per day per well, and that's gross production. At present, 10 of our 12 second half wells are now on production, and 2 are under facility construction.

Obsidian Energy set another record in the third quarter for meters drilled with a single bit and bottom hole assembly. The company drilled 17,278 meters of open hole on this well for an overall cost of just $76 per meter.

In the Mannville, we drilled our 3-well program in the third quarter, with 1 well on production as of September 30 and the remaining 2 wells by the end of October. While the first well encountered lower permeability and pressure than expected, our second and third wells moved to higher-pressure areas of the reservoir and have significant liquids rates. These 2 wells are currently showing free condensate rates of 35 barrels per million standard cubic feet relative to expectations of 10 barrels per million. Overall liquid read from these wells are 60 barrels per million, more than double type curve expectations. We expect these yields to increase project rate of return by approximately 20%. We are maximizing the liquids potential of these wells by utilizing a downhole choke to stabilize gas rates at approximately 4 million standard cubic feet per day.

I echo Dave's comments on being proud about what we have accomplished this quarter. We have great assets, and the team had a lot of fun developing them in the third quarter. Our current activity has established a strong foundation for 2018.

I'd now like to share some details of our 2018 capital program. Our significant portfolio optionality allows us to shift capital allocation in response to various commodity price scenarios and deliver a returns-focused capital program entirely supported by funds flow from operations at current strip. As Dave Hendry touched on, our hedge position provides cash flow certainty, enabling our capital program to withstand more than a 10% decline in Canadian dollar realized oil and gas pricing before exceeding our funds flow from operations. This gives us strength in a weak commodity environment. The more relevant conversation given this recent strength in crude prices is the flexibility we have to respond in the second half. Our program is 60% H1 weighted. And as commodity prices play out, we have the option to enhance development capital levels in the second half. We have a substantial project inventory ready to execute.

Our capital program supports the ongoing costs of business such as environmental, infrastructure and maintenance but also includes nearly $15 million of onetime regulatory costs for the year. For example, we have a license-to-operate requirement in Peace River associated with AER Directive 084, where we will conserve, gather and process gas to meet a September 2018 regulatory deadline.

Our development capital program is approximately 50% weighted to the Cardium; and 10% to 15% each to our Deep Basin, Alberta Viking and Peace River assets; as well as an additional 15% to optimization of existing wellbores. The projected capital efficiency of our 2018 development program is approximately $15,000 per boe, based on the 12-month forward-production associated with each of those projects. Just under $45 million will go towards the Cardium, drilling 6 Pembina integrated waterflood wells and 2 Willesden Green short-cycle Cardium wells. We continue to place our horizontal wells in the bioturbated rock just below the upper good-quality reservoir to ensure we access reserves in both the cleaner intervals above, as well as tapping into some portion of the undrained reservoir in the lower bioturbated interval. This is the approach we have used in 2017 wells and in our prior wells, specifically our 2015 and '16 Willesden Green programs which had very strong results.

Additionally, we will spend approximately $5 million on integrated waterflood and optimization opportunities within the Cardium. We are using a hybrid type 1 and 4 approach in Pembina where we will convert existing verticals to injectors to support new drills, a much more capital-efficient approach in a year with some one-off license-to-operate capital requirements. $12 million from the Cardium budget will be allocated to non-op primary drilling by our working interest partners in the area, and $4 million to land consolidation opportunities and seismic.

We plan to drill 3 wells, spending approximately $11 million, to continue the development of our Deep Basin position in 2018. We have high-graded our 2018 inventory to target liquids-rich high-pressure locations that generate robust rates of return even with the current AECO outlook. Designing simpler wells to mitigate risk and increased length with individual legs to drill faster has driven cost savings that attract capital to the Peace River area. We plan to invest approximately $8 million to drill 5 gross wells. Even with the end of the carry, we expect to drill highly economic PROP wells in 2018.

Approximately $9 million will be allocated to Alberta Viking. We will drill 6 wells, offsetting our 2017 program; and expect comparable production results. We expect slightly enhanced economics on our 2018 program using multi-well pads close to existing infrastructure and by continuing to truck clean oil. We have identified more than 50 individual optimization projects to debottleneck, consolidate infrastructure and test [our full] potential within our portfolio, spending approximately $14 million in 2018. This will generate some of the most capital-efficient spend in our 2018 budget, projected at less than $10,000 per boe per day. This is a focus in the year, with additional regulatory requirements, so we do not expect the same quantum of capital to be allocated past 2018.

A combination of our Cardium waterflood results, the success of our first Deep Basin program and PROP and Alberta Viking continued delivery leave me very excited for our 2018 development and the continued performance our team has delivered in 2017.

That concludes our formal remarks. I'd now like to turn the call back over to the operator to open up for Q&A.

(Operator Instructions) Your first question comes from the line of Sam Roach from Canaccord.

So first question is for Dave here. On the royalty sale, were those existing royalty assets, or did you manufacture them? And can you just help me understand? Do you see more opportunities to monetize existing assets? And what we can expect from that in 2018.

It wasn't a manufactured royalty. It was on third-party land. So on a previous sale, we had encumbered it with a GOR position. And then we sold this third party, so there's no ongoing cost to Obsidian oil past this disposition. And as far as ongoing, we don't have any plans to continue to sell any GOR assets, but obviously we look at opportunities as they come about.

Great. And just a quick follow-up. Could you give any more details on the Mannville wells during the quarter, maybe a breakdown by well by well or test durations or anything like that?

Yes, sure. It's Tony here. So on the [14 to 30] well, that was the first well we drilled. That's been on flow for about a month now, so we're about 30 days in on that well. As is mentioned in the call notes, we did encounter a lower reservoir quality there, so really kind of a degraded perm and a little bit lower pressures. That well came on at about 3.2 million a day, and it's stabilized down at about 2 million a day right now. So taking the learnings from that, and really ultimately that was just drilling into a different part of the channel and encountering a bit tighter rock. Second well was [2 of 7], just south of the 14 to 30 well but into a different channel. That's been on production about 3 weeks, definitely stronger pressure there. We maintained the downhole choke in that well up until about a week ago. And that well is flowing into our Willesden Green facility. And as we mentioned in the call, that has come on with higher free liquids rates around 30 barrels per million of free condensate and another 30 of NGLs associated with that. And then finally, the [2 of 3] wells, been on production for just about 2 weeks now. This encountered the highest pressure at about 27 MPa reservoir pressure and again similar liquids rates to what we saw in the 2 of 7 well. We've got a downhole choke in this well still, and we're going to keep it flat at about 4 million a day just to manage inflow to the facility. With these big liquids rates, plugging into the facility has been a bit of a challenge, so we're just managing that right now as we stabilize flow rates.

(Operator Instructions) Your next question comes from the line of Thomas Matthews from AltaCorp Capital.

Just sorry for my voice, but just quickly on the going to the shorter-cycle Cardium program in 2018. So just wondering. The Willesden Green wells that you'll be drilling, are those going to -- are the expectations that those are going to be similar to your 2015 and 2016 wells? Because from what I recall, those were still into a waterflooded acreage. Or will you be pushing into more halo-type virgin rock in 2018?

Yes, Thomas, it's Tony here. Yes, we're definitely drilling into the halo, so this won't be similar to those 2015, '16 wells where we were in the heart of a well-supported waterflood. These will be kind of that typical halo production profile that you would see from wells offsetting our main unit production. So these will be off to the east of our -- the main unit development.

Good, okay. And then just on kind of the non-op partnerships, would you disclose how many wells that would get you or what your kind of average working interest is there?

No. We're still waiting. It's placeholder capital, for the most part. We [had a lot effect] to a few wells, but ultimately that will shape up as the year progresses.

There are no further questions at this time. I turn the call back over to the presenters.

Thanks for the questions, everyone.

As we mark our first quarter results as Obsidian Energy, the first full quarter, this is often the time when I use some sports analogy to talk about the future of the company and what to expect. This quarter feels different; no interpreting required; just good, solid results. This is an exciting time for our business, as Tony and Dave said before me. We've been working hard at all levels of the organization to hang numbers and deliver a plan that demonstrates the power of our portfolio. Now is the time to keep this positive momentum going and to solidify our place among the very best of our peers, and we intend to do just that.

We look forward to catching up soon with all of you.

Thank you for your continued support, and have a great morning.

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