Obsidian Energy Ltd (OBE) 2017 Q2 法說會逐字稿

Good morning. My name is Carol, and I will be your conference operator today. At this time, I would like to welcome everyone to Obsidian Energy's Second Quarter Results Call. (Operator Instructions) At this time, I would like to turn the call over to Paul Surmanowicz, Investor Relations.

Good morning, and thank you for joining us on this conference call discussing our second quarter 2017 results. The format of this call will be audio only.

With me this morning is President and Chief Executive Officer, David French; Chief Financial Officer, David Hendry; and Vice President, Development & Operations, Tony Berthelet.

Before we begin, 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 remind you it is subject to the risks and uncertainties affecting every business, including ours. Please refer to our public disclosure filings available on both the 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.

I would now like to turn the call over to David French.

Thank you, Paul. Good morning, everyone, and thank you all for joining us. I can tell you that my opening remarks have changed a lot over the last week. With all the recent enthusiasm inside the company on reporting our results and priding where we're heading, it was tough to look at an empty seat at our Board of Directors' table this week. As you can understand, my comments and my sentiment should start there.

On July 7 of this year, just before the Calgary Stampede, Rick George, along with George Brookman from our board and the rest of our executive team, rang the opening TSX bell, signaling the new chapter of Obsidian Energy Ltd. We all shook hands and celebrated a restructuring and reemergence of something we believe is quite special. For all the joy around that podium, it signaled a new beginning.

Then last week, we lost a special leader. There had been and forever will be few people who symbolize the energy industry as Rick did. His life and contribution to the oil business in Canada was truly extraordinary. Our company had the true privilege of his stewardship through some complex times, and it was his sense of purpose and commitment that got us to this new beginning. Rick, we will miss you and we will work hard to keep your enthusiasm as a part of our very DNA.

When I step back, which is not easy to do, from the sadness of this last week, and I try to look at our quarter, I know why we all felt that shared sense of optimism. These results marked the first opportunity for Obsidian Energy to speak on its own behalf through performance, and we have reason to be proud.

Despite challenging and wet weather conditions across the province, we had a very active second quarter and finished with quality production numbers of almost 30,500 barrels a day. The quarter saw us catch up from a near standstill in 2016 on maintenance and turnarounds in support of our base production. With all that renewed activity, operating costs ran $14.27 net of carry as we planned. And with our strong focus on asset deliverability and uptime, we are guiding annualized operating cost net of carry in the $13 to $13.50 per Boe range.

We delivered funds flow from operations for the quarter of $43 million, which is 20% less than the same quarter in 2016. However, the company is producing 50,000 fewer Boes. That speaks volumes to the much improved cash margins and greater efficiency and the operations in development of the company.

I also think it's important that we do not have a single recordable injury in the quarter, even with the weather and high pace of activity. It won't be news to the folks on this call that the past several months have seen increased headwinds for our industry, with volatile commodity prices and U.S. Canadian exchange rates. We are taking a prudent approach in adjusting our activity for the second half of the year to spend about $20 million less than originally planned on capital. About 3/4 of that reduction comes in the form of reduced development, including 19 fewer waterflood injectors and another 1/4 in reduction of nonproductive capital.

Our base well management early development results give us confidence that these reductions will not alter our outlook. We believe we'll be able to demonstrate both self-funded double-digit growth for the fourth quarter of 2016 to the fourth quarter of 2017 and meet our full year 2017 production guidance.

We've reduced our debt levels by over 80% since the beginning of 2016. We plan to protect our balance sheet. We continue to extend our hedge book to support 2017 and 2018 development for both our liquids and emerging gas portfolio and watching every dollar we spend.

The past month has been challenging for our shareholders, as the U.S. Securities and Exchange Commission disappointedly filed a claim against our company related to accounting issues that the company itself discovered and reported back in 2014. We respect the SEC's role and we'll work through this process in the background and believe it will not meaningfully affect our day-to-day business and finances. We anticipate resolution will take some time, and we will update shareholders as new information is available.

Our main focus, and we will not be distracted from it, is delivering on our portfolio, both in base production management and key development area growth. Our second half capital is off to a strong start, with 5 rigs currently active across Alberta. We are seeing robust indicators of waterflood response in the Cardium, including early suppression of gas oil ratios and shallowing declines and our new well results across the province look promising. This was a tough last week, but we intend to work hard to live into a shared and promising vision for this new company.

I will now turn the call over to Dave Hendry to discuss our second quarter financials.

Thank you, Dave. We had a strong second quarter, delivering corporate production of 30,436 Boe per day, 3% ahead of analyst consensus. This was driven by repair and maintenance work resulting in higher reliability in our base production. Consequently, we are maintaining our full year guidance of 30,500 to 31,500 Boe per day, while reducing our full year capital budget by $20 million to $160 million. We are delivering second quarter funds flow from operations of $0.09 per share, 5% ahead of analyst consensus. The stronger funds flow from operations was primarily due to higher production results and better realized pricing across our product streams. In the second quarter, we transitioned to a reserve base syndicated credit facility with a group of 9 lenders. The underlying base -- borrowing base is $550 million, less our senior notes outstanding, for $410 million of current availability. The new facility has several important benefits, including providing a flexible facility that can grow alongside our robust, long-life asset portfolio and further improving our relationships with our key banking partners.

As of June 30, our senior debt outstanding totaled $392 million, including $275 million drawn on our $410 million credit facility. Our balance sheet is in a good place, with competitive leverage metrics, including senior debt-to-EBITDA ratio of 1.9x. We layered in additional hedges for the second half of next year to maintain our strong financial position and increase the certainty of our revenues. We now have approximately half of our oil production hedged through the first half of 2018 and over 25% of our oil production hedged for the remainder of next year at around USD 50 WTI. Our natural gas -- on the natural gas side, we have an average of 30% of our natural gas production hedged through to the end of next year. We have an active Mannville program in the second half of this year, so we hedged some additional volumes in the first and second quarter of next year.

In the second quarter, we closed a previously announced minor disposition for $10 million. We also closed a small tuck-in acquisition in Peace River, which provides additional attractive drilling opportunities.

I will now pass the call to Tony Berthelet for an operational update.

Thanks, Dave. We had an active second quarter in the Cardium and made good progress setting up our waterflood program for the second half of '17 and for future development. We drilled 4 injectors and brought on 17 injectors in Willesden Green to provide pressure support for previously drilled horizontal wells.

In PCU 9, existing vertical injector reactivations are showing better-than-expected results, with gas-oil ratios decreasing and oil rate increases in offsetting producers. We are currently drilling 1 rig -- running 1 rig in PCU 9, drilling 3 horizontal producers, followed by a vertical injector program, and we'll move another rig to Willesden Green near the end of Q3.

In our Cardium area, we reactivated our 800 Boe per day of production from an existing field that was shut in last year due to third-party outages. The facility was repaired ahead of schedule and we optimized our gathering system in the area to ensure ongoing production reliability. This change in timing brought forward some incremental OpEx to the quarter ahead of schedule, but also came with an early production bump.

In Peace River, we benefited from favorable weather conditions that allowed us to continue development well into breakup, drilling and bringing on production 5 wells in the second quarter. We currently have 2 rigs running in the area and have 12 wells planned for our second half program.

In the Alberta Viking, we resolved minor artificial lift issues on select wells drilled in Q4 of '16 and saw our Viking well performance increase back to our industry-leading type curve. We restarted Viking development in June and have now finished drilling all 10 wells of our second half program. We expect these wells to be on production by the end of September. And early flowback results from these wells are encouraging and on track to exceed expectations.

In the Mannville, we drilled our first well in July, with costs and wellbore placement as expected. We plan to have the first well on production next month and the remaining 2 on production early in the fourth quarter. We saw several offsetting competitor well results -- wells show strong results, which supported our decision to increase our average working interest in our operated 3-well program by approximately 10% to an average working interest of 80%.

Going forward, we continue to focus our efforts on our waterflood portfolio in the Cardium. We will bring -- continue to bring on volumes in both PROP and our Alberta Viking, as well as monitoring industry activity and delivering competitive results at our Mannville development.

Finally, optimizing and maintaining our assets across the entire portfolio remains a key focus for ensuring safe, efficient operations. I'd now like to turn the call back over to the operator to open up for Q&A.

(Operator Instructions) And our first question this morning comes from Greg Pardy from RBC.

Just a couple of questions. The first one is just given the spending in the first half, David, how would you see just the progression of spending in the third and fourth quarter? And then secondly, just given the reduced CapEx, could you give us any sense as to where you'll exit 2017, maybe at a corporate production rate? And then if you can get a little more granular, that would be great.

I'll take the first and I'll probably let Tony talk to production. I got a pretty good sense of where the second half is. I think we're going to spend probably half of our capital in the last month and the 2 months ahead of us. The third quarter is our highest intensity spending quarter for the year. And so I think where we see our trailing spend is really going to be fourth quarter and largely, it's going to be deferment of a little bit of injection and do a little bit of nonproductive capital, especially as it relates to ARO. Tony, you want to take the exit rate question?

Yes, so we're still providing, even with that capital reduction, we're still maintaining our guidance of 30,500 to 31,500. And we're still providing guidance in terms of 10% growth, low double-digit growth for the fourth quarter of '16 over fourth quarter of '17. So that guidance has remained unchanged.

And I think, Greg, we'll have an opportunity to talk to the drilling results here in the next month or so. So there'll be a lot of exciting things to talk about.

Our next question comes from Sam Roach from Canaccord Genuity.

Following on from Greg's question there. Are you able to quantify the potential 2018 impact of the CapEx reduction?

Yes, so I don't think we expect there to be a really significant change to the volumes. Obviously, we've got -- the nice thing about the portfolio is we'll probably do a little bit of moving first and second quarter between sort of intermediate and short-cycle investing. So I don't think you'll see a significant change in our perspective. I do think the way we're looking about pricing for next year is we're going to have a capital program that is probably similar in size and scale to this year. So we kind of expect very similar volumes. So the real question then will be what happens kind of with pricing beyond that? But that's why we've extended our hedge book, so that we've got 50% accrued and kind of 30% of gas covered for next year. So we've got a pretty good baseline for our funds flow in with which to invest.

Excellent, thanks. One other quick question. How much production is still shut in that could be brought back on, just like the 800 Boes a day that were brought back on in Q2?

It's Tony here. Thanks for your question. Basically, we've -- that 800 Boe per day was the only production we have that's material that was shut in. The rest of our focus for the second half of the year will be focused on optimization opportunities. So it's recomplete activity, reactivations. But in terms of material adds, that'll be more normal course of business activity, not so much a field that was shut in.

(Operator Instructions) And our next question comes from Jeremy McCrea from Raymond James.

I just was curious with your waterflood, now that it's been, call it, half a year. If you're seeing some of the initial results and contemplating changing anything that you've done with the waterflood program for maybe future injectors or if there's any kind of early indications of things you want to change? I'm just trying to understand maybe as you head into 2018, if there's anything different in terms of cost savings or enhancements that you could do to kind of get that payout back under 2.5 years or so, 2 years?

Jeremy, it's Tony here. Thanks for the question. Yes, we're absolutely very excited about our waterflood activity, specifically in PCU 9, where we did a bunch of reactivations of existing vertical injectors. And that has actually set us up to deliver a 2018 program of horizontal drills that won't require incremental vertical drilling to support those horizontals. So really, as we talked about at the Analyst Day, we're going into those areas of the field where we can reactivate wells and really reduce that payout on those investments, on those horizontals, by making use of the existing vertical injectors. So in the corporate presentation, we gave a couple of examples of that. But in PCU 9, in particular, we've been very encouraged. GOR suppression and oil rate response is ahead of expectations from our model, which we're now updating to then look at other places where we can just reactivate vertical injectors to reduce that capital spend.

Do you expect to see production response within, I guess, a year on average? Or are you still thinking it could be a bit longer than that?

No, what we've seen so far is GOR response in 3 to 4 months. And then maybe a month later on that PCU 9 example, we're already seeing an oil rate response. So as I said, much quicker than what we initially modeled, which is very encouraging. And I think overall, it speaks to the success and the proven technology of waterflooding in both Pembina and Willesden Green, we're not doing anything new here other than reactivating waterfloods and getting them going again. So this has been encouraging, that we're seeing response much sooner than what our models were suggesting.

Our next question comes from Thomas Matthews from AltaCorp Capital.

Tony, this question for you at the start. Just on the Viking side, the artificial lift issues that you had. Just wondering if you could touch on those really quickly and just maybe some of the mitigation tasks that you guys have completed to avoid that going forward.

Yes, you bet, thanks, Thomas. So the biggest challenge that we had with bringing these new wells on was the combination of sand and wax or asphaltene. And really, it was a collaborative effort between our field operations team, our production engineering team and our techs in the field to come up with solutions for that. Ultimately, what we ended up doing was coming up with a batch program of chemical, and we used some of the leading indicators in terms of torque and power usage on our pumping equipment to determine the frequency of that batching. And ultimately, that's resulted in bringing those wells back on. That production has flattened out and actually come back up to our type curve expectations. So we'll be applying those learnings going forward on our, this 10-well program that we just drilled. So we're pretty encouraged by that and a great effort by the guys in the field and our production engineering team, to come up with a solution there.

Okay, great. So there won't be any of those -- or potentially any of those declines kind of mid-curve, like you saw in the first batch of wells?

I think we'll always get surprises, but it's our expectation that we've got a solution that's dealing with that sand and asphaltene problem, which I think definitely mitigates any of that mid-curve reduction that we saw.

Okay. And then just finally, on the Mannville program. If you drilled some of these wells and we've seen, like you mentioned on the call, some big wells from offsetting operators, is there any risk of takeaway capacity restrictions there? And how -- I guess how big can you ramp the Mannville program given where some of the infrastructure has been in the area?

Yes, great question. So again, we're really encouraged by some of the offsetting competitor activity. Right now, everything that's in our plan for both 2017 and '18 has firm takeaways. So we're able, and the reason we focused on this area, was because of egress not being an issue. So both TCPL egress and infrastructure, our own-operated infrastructure egress, is not a concern for us for these wells. Now if we get a huge surprise in terms of rate, then we'll have to understand what that looks like in terms of full throughput. But our expectation right now is, if we meet type curve performance, we have space for all of that production.

We have no further questions in queue at this time. I'll turn the call back to Mr. David French for closing remarks.

Thanks for all the questions from the call. As I said in my opening remarks, this quarter is honestly a sad ending and a new beginning. Our collective heart goes out to Rick George's family, and we believe that living into the new Obsidian Energy, disciplined, relentless and accountable, to honor his and our pasts and frame our company's future. Take care, everyone, and we wish you a good rest of your summer. Thanks for the call.

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