Obsidian Energy Ltd (OBE) 2016 Q4 法說會逐字稿

Good morning. My name is Chris, and I will be your conference operator today. At this time, I would like to welcome everyone to Penn West's year-end and reserves results 2016 conference call.

(Operator Instructions)

Thank you. Paul Surmanowicz, Investor Relations, you may begin your conference.

Good morning, and thank you for joining us on this conference call discussing our 2016 year-end and reserves 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 and Operations, Tony Berthelet.

Before we begin, I'd like to point out that we will refer to forward-looking information in connection with Penn West as 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 Penn West, or affect future outcomes for Penn West. I would now like to turn the call over to David French.

Good morning, everyone, and thank you for joining Penn West to discuss our 2016 year-end results and reserves. In 2016, Penn West undertook a major renovation, that reshaped every aspect of the business. The result of these changes left us a much stronger place, offering investors a nicely balanced portfolio that is liquids-weighted, underpinned by shallow corporate declines, and generates self-funded double-digit growth, while maintaining a healthy balance sheet.

Throughout the year we focused on three main things. First, we simplified our balance sheet by right-sizing our debt through targeted dispositions. Second, we focused our attention both in people and capital, on a small number of key development areas. Third, we recast our reserves to reflect the development schemed best suited for today's price environment.

By the end of the first quarter, we will formally remove the For Sale sign from the yard. Our CAD1.4 billion in proceeds last year were used to reduce our debt by a total of 76%.

This positions us nicely within our peer group, with a healthy debt to funds flow ratio of only 2 times, well within financial covenants, and settles us into normal banking flexibility. We'll remain conservative and disciplined, with plans to apply free cash flow against our debt throughout this year.

What has emerged from our renovation is a portfolio with industry-leading positions in the Cardium, Peace River, and Alberta Viking, raising a combined roughly 30,000 barrels of oil equivalent a day, with over 60% liquids. What we like about this portfolio is the ability to build a steady cash flow stream from the shallow declines of our Waterflood program in the Cardium, steadily manufacture heavy oil business in Peace River, and leverage short cycle investments through the high rate infrastructure leveraged returns of our Alberta Viking position.

Our remodeling has led to a more efficient business. Not only through the sale of high-cost assets, but through a renewed focus on efficiency throughout our operations. 2016 saw our funds flow from operations fall 27% to CAD182 million, but on the back of a 36% reduction in volumes due to divestments, and a 23% reduction in blended commodity price.

That was only possible because our margins grew 12% to over CAD18, inclusive of hedging, due to operating costs being down 30%, or over CAD5 a barrel. This is a focus that will continue throughout this next year, to make sure we are earning the most out of every barrel. We also cleaned up our reserves to more accurately reflect our development plan outlook and the current price environment.

Tony will speak to the reserves book shortly, however 2016 we saw proceeds from our divestment program exceed the change in their asset value. Additionally in the Cardium, new reserves tied to the results from our expansion of Waterflood, and a shift in the focus in Peace River towards cold flow, helps us think hard about where we're headed in the future. I will now turn the call over to Dave Hendry to discuss the year-end results.

Thank you, Dave. Last year, the Company embarked on a comprehensive top to bottom cost review reduction initiative. We were able to find meaningful cost reductions by improving many of the internal business processes, in addition to benefiting from savings and service costs. Overall, we reduced our operating costs by approximately 30% to CAD13.18 per barrel of oil.

As a result of these operating cost savings, we generated cash margin by 12% last year, despite a challenging commodity price environment. We generated strong 2016 funds flow from operations of CAD182 million, or CAD0.36 per share.

We expect to generate higher funds flow in 2017 than last year, with only about half the production volumes. This allows to us self fund our entire CAD180 million capital program.

Our budget is expected to provide double-digit organic growth in our key development areas from the fourth quarter of 2016 to the fourth quarter of 2017, and ample flexibility to respond to fluctuations in commodity prices. Last year, we closed asset dispositions for proceeds of CAD1.4 billion, to bring our year-end long-term debt down to CAD469 million, compared to CAD1.9 billion at year-end 2015.

Penn West is now at a comfortable and appropriate level of debt for our new size. With debt levels corrected, the Company is on track to complete its asset disposition program by the end of the month.

We have closed an additional CAD65 million in asset sales this year, with the remaining CAD10 million to be completed shortly, bringing our sales program to a close. I will now pass the call to Tony Berthelet to discuss operations and reserves.

Thanks, Dave, and good morning, everyone. 2016 production averaged 54,990 BOE per day, at the high end of our guidance of 52,000 to 55,000 BOE per day. This success is largely attributed to continued high reliability of our base production, strong Q1 performance in Cardium and PROP, and our successful second-half drilling program of 36 wells that added approximately 3,000 BOE per day to our exit volumes.

Going forward, our focus in the Cardium is based on integrated Waterflood developments in Pembina and Willesden Green. Combining new horizontal producers with simultaneous injection drilling to support reserve development and arrest base decline. In Pembina, at PCU 9, we'll focus on drilling a three-well vertical injection pattern to support existing horizontal producers in the first quarter.

After breakup, we plan to drill an additional three horizontal producer wells, plus 15 supporting injection, vertical injection wells. We are also working with our partners in PCU 11 in preparing for our second-half development program.

In the J-Lease area of Pembina, we fracture stimulated the two horizontal wells drilled in late September, using a cemented liner system, and brought the wells on production in November. This year we plan to focus on Waterflood optimization opportunities in J-Lease, including converting producing wells to injection.

We are already seeing Waterflood response in line with expectations in several areas, based on earlier horizontal injector conversions. For example, one of our Q4 2015 horizontal injector conversions has provided Waterflood support to three offsetting wells in less than six months, confirming our Waterflood performance predictions.

In the Crimson area of Willesden Green, we drilled and completed three horizontal producers and three vertical injectors. The producers were brought on production in early January, and are performing in line with expectations. Prior to spring breakup, we plan to drill 15 vertical injection wells to support producers, with an additional six vertical injectors planned once activity resumes in the area.

Water injection infrastructure is progressing well as we optimize and upgrade some of our projects, in preparation for our development program in the second half of the year. In Peace River, the fourth quarter saw us drill and rig release the remaining 17 wells of our 19-well program. Through simultaneous drilling and facility construction operations, we were able to reduce per-well costs to CAD2.4 million, or approximately 15% below budget.

This year, we will increase the development pace in the Peace River area, with a program of 24 producing wells. We are currently carried on 90% of our capital and operating commitments through our joint venture partner, and we forecast the carry to be finished by the end of 2017.

In the first quarter of 2017, we drilled three wells and brought on production four additional wells. We currently have two rigs running in the area, and plan to bring on production an additional 21 wells during the second half of the year.

In the Alberta Viking, the two remaining wells of the 11-well program were drilled in the fourth quarter, and were brought on production -- sorry, that were drilled in the fourth quarter were brought on production in January. The wells continue to exceed expectations, with average production per well coming in approximately 25% ahead of the average industry type curve in the play.

In the second half of the year we have budgeted to drill seven wells in the Alberta Viking. We believe the success of these wells can be attributed to the novel approach we are taking with our completions in the area, including foam fracs.

In the second half of the year, we have budgeted to drill seven wells in Alberta Viking, as well as four non-op wells. We are currently working on a debottlenecking project, which will allow us to expand our capacity and our gas infrastructure.

As part of our new ventures plan, we are aiming to expand our reach by testing deeper hydrocarbon formations below our Cardium rates, primarily in the Mannville, throughout the second half of the year. We are encouraged by offsetting industry activity, showing potential for high production rates and liquid yields in the 30 to 40 barrels per million range.

We have budgeted to drill three Mannville wells, our first operated development into the multi-horizon potential across the Cardium area acreage, and we are partnered in an additional four Mannville wells. We will continue to evaluate our portfolio against commodity prices throughout the year, and if prudent, capital will be reallocated to more oil-driven parts of the portfolio. That being said, this area has a great potential for the Company, as we have approximately 700 net sections of secondary rights in our portfolio, and a gas processing advantage.

Now I'd like to talk about reserves. Our 2016 reserves reflect the many changes we have undergone as a Company in the past year, and are better aligned with our near-term development plans and the current commodity price environment.

In the Cardium, we are starting to receive recognition for our Waterflood success in the area. Last year, we demonstrated increased reservoir pressure from injection, and as a result, received 2.1 million barrels of Waterflood additions. As we continue to demonstrate active natural gas suppression and production response as forecast, we expect there will be additional reserve recognition of our methodology at year end 2017.

Our reserve books changed meaningfully last year, as a result of the numerous dispositions across our asset base. In 2016, we closed asset dispositions for total proceeds of approximately CAD1.4 billion, which was above the associated PDP and 1P before tax present values of CAD1.1 billion and CAD1.2 billion respectively, meaning our dispositions were accretive to our shareholders on a 1P metric.

In Peace River, we have deliberately chosen to move to a cold flow operation over the past years, recognizing that primary development has more value at today's commodity prices versus thermal development. As a result, we cleaned up the reserve book at Peace River to remove the thermal undeveloped plan. These thermal reserves had only CAD20 million of net present value, but had an associated development capital of CAD389 million.

In general, we were very deliberate and conservative with our undeveloped reserves. Our current reserves account for only approximately 1.5 years of development in Peace River and the Alberta Viking, and no development in the Mannville. We feel that successful execution in these areas in our 2017 program, we can begin to formally recognize the significant running room we have in these plays.

We received positive technical revisions acknowledging both lower operating costs and improved performance across our portfolio, which offset the economic revisions, due to lower commodity price assumptions. The PDP before tax present value, discounted at 10%, received a positive technical revision of CAD486 million versus negative economic revision of CAD223 million. The proved plus probable before tax present value, discounted at 10%, received a positive technical revision of CAD476 million, versus a negative economic revision of CAD295 million.

The 2016 operated development cost of CAD5.86 per BOE, or CAD11.26 per BOE excluding the impact of our partner capital in Peace River, reflects the capital efficiency of converting liquid resources into reserves, and undeveloped reserves into developed reserves in our key development areas. In 2016, funding and development costs, inclusive of changes to our future development capital, on a 2P basis was CAD16.45 per BOE.

These costs reflect our limited spending in the first half of the year, which was focused on base and facility maintenance, which has a limited reserve impact. Finally, the Company's 2016 recycle ratio was approximately 1.1 times. I'd now like to turn the call back over to the operator and open up for Q&A.

(Operator Instructions)

Your first question comes from the line of Adam Starr from Gulfside Asset Management. Your line is open.

I just was wondering if you could comment on the Mannville well that you partnered in last quarter, and whether the results have been disclosed, and what that leads you to expect in the future wells?

Yes, it's Tony here. So we partnered with the well in Q3. Brought that well on production in Q4, and those results are public information.

I think the biggest challenge we saw with the drilling and completion of that well was there was, some challenges getting the well to total depth, primarily in the build section of that well, which resulted in a side track, and put part of the horizontal leg out of the zone. So those well results were less than expected.

We plan to take those learnings and definitely apply those to what we're planning to do in our second-half program, but ultimately the operator that was drilling that well has drilled several wells in the area. This was more of a one-off in terms of the drilling problems, getting to the zone, and then ultimately not staying in the zone. So we're encouraged by the initial results, but believe that there's more optimum placement of the well bore to improve results.

Thank you very much. Is it mostly gas? What's the composition of the production?

Yes, you bet, it's gas with about 30 to 35 barrels per million in that part of the reservoir.

Okay. Thanks.

Your next question comes from the line of Thomas Matthews of AltaCorp Capital. Your line is open.

I just had a couple quick questions. Just on retaining some of your legacy acreage there in that 3,500 BOE that has higher op costs, are there any thoughts on your op cost guidance here in 2017, just with integrating that? Would that be more of a proportionate increase, as per your new guidance there? Or do you expect op costs to remain the same, as you had previously guided towards?

No. Hi, it's Tony here. No, we'll maintain previous guidance. What we're doing with those legacy assets, now that they will be part of the go-forward portfolio, is we'll be looking to pay a bit more attention to how we manage OpEx in those assets. Not that they've been ignored in the past, but we will definitely be doing a full court press in terms of finding out how to make those assets more profitable.

The biggest take-aways are going to be looking at recomplete and reactivation opportunities to get production up, so that on an OpEx per BOE basis, we are maintaining guidance. Those areas definitely are challenged from an OpEx perspective but we believe we can get them back in line with focused effort on reactivations and some pipeline work to get those wells started again.

Perfect. Just on the Waterflood, so you've seen some recognition from the reserve engineers. I don't really have a good feel for what inning you're in there, if that's new Waterflood, because there are a bunch of legacy Waterfloods in the area.

Just wondering if you could comment on potential reserve recognition pace going forward. Will that be accelerated? Clearly, as you put more capital towards the Waterflood or the point of my question, if it takes 12 to 18 months to receive recognition on Waterflood, where would you be in terms of the reserve engineers giving you credit for some of the new stuff that you're doing?

Great question. Again, it's Tony here. So we received recognition for a combination of both the existing Waterfloods that we have in place in Crimson, but also some of the future development capital that we're spending. I gave a bit of a brief update on our vertical injector drilling program, and we did receive some 2P recognition for that development plan.

I also talked about the J-Lease area in Pembina, and the well results that we've seen there. As I mentioned, that was a six month time to fill up, and we're seeing gas/oil ratio response, as well as already oil response.

I'm pretty optimistic that we're going to get additional reserve recognition in Pembina. I'd probably say 95% of our reserve recognition on Waterflood, 90% anyways of reserve recognition on water flood was in the Crimson area last year, and we'll look to add some reserves to our Pembina assets as well, given our development plan in that area.

As for the total number, I'm not sure where we're going to end up with, but I'm really encouraged by the results we're seeing. This quicker response, being less than six months, is definitely telling us that we are picking those higher pressure spots to the reservoir where time to fill up is less, and I think we can expect to see better results in terms of reserve recognition in Pembina.

Perfect, that's it from me. Thanks.

Your next question comes from Ken Gilpin of Sound Investments. Your line is open.

I was wondering what the cash flow was going to look like in 2018 and 2019?

It's Dave Henry here. So funds flow from operation is going to be above last year's number, which we reported. It was going to cover our entire capital program of CAD180 million. So we didn't provide any specific guidance on the number, but it's going to be higher than last year.

Ken, thus is Dave French. I guess I'll add on. I think your question was 2018, 2019 as well?

Yes, that's right.

I think we're probably not -- we're looking for, I think the general structure is obviously that's very price dependent.

Sure.

It would be your perspective on both liquids and gas. We're intending to maintain our portfolio weighting of 60%-plus liquids. That will give you a sense a little bit of how to model us.

We're certainly bullish on moderate to midterm pricing on oil and it all depends a little bit on gas. I would say, the basic premise for us would be grow double-digit production on Q4 to Q4, and think of it that way. So think of it as double-digit growth, and then with a 60%, 65% liquids weighting, you can get a perspective on cash flow.

But as Dave said, we intend to be fully funded as to our capital this year. Our current capital is about CAD180 million, so we'll do that. We'll do that within our funds flow, with the expectation that we'll be able to grow that year-over-year, essentially by being able to put pretty efficient capital to work.

Well, thank you. I had one other question, and I'm not very knowledgeable on drilling and things like that. I know you were going to, in the Cardium, I know you were going to drill down further, two wells in the Manville area, that you're probably going to drill in summer, and were going to drill a lot further.

What do you expect to get? I know there's about six different layers in that Cardium. You're going to drill down further. What do you expect to find?

You bet. It's Tony here again. So we're going to be looking to target the upper Manville section, so primarily for gas, and again, I would expect to see in that -- I won't give production ranges yet, because I think we need to see what that final offset competitive results look like, but we'll be targeting upper Manville gas with that 20 to 30 barrels per million of liquids associated with it. On a BOE basis, probably in that 800 to 1,000 BOE per day.

Again, I'm a real amateur, that if you drill down further they're going to get more tar type of areas. Would that be correct or -- in.

No, this is definitely a gas prone area. It will be primarily liquids-rich gas.

Okay. That's good. Okay. That's all I had.

(Operator Instructions)

Your next question comes from the line of Juan Jarrah or TD Securities. Your line is open.

Can you give us some color on your disposition, your royalty disposition? Just wanted to get a sense of what cash flow was associated with that. I'm happy with a number for 2017 or a number for 2016. Just wanted to get a sense of how that would impact your funds flow?

David?

So as far as -- you're talking about as far as the Gore -- hold on a second. We're just looking for a number here.

Yep, this is the three holes in Gores that you sold instead of the legacy stuff.

As far as we obviously got a great sales price on the disposition, but as far as the funds flow impact, we're not expecting it to have a material impact to our funds flow for 2017 going forward.

Okay. The other question I had was -- sorry.

Just wanted to comment. This is Mark Hodgson here. Just wanted to comment that the offset we had looked at to the three hole transaction was the Pear Creek area.

The production we retained by maintaining that asset offsets the lost revenue from that Gore. Dave's referencing funds flow staying consistent in terms of guidance. That's what he meant by that.

And then obviously that's accretive on production because keeping the additional outer Cardium acreage gives us higher production for the year going forward.

The other question I had is you alluded to your Manville capital program, you've got three wells in the budget, or three operated wells in the budget. I just want to get a sense of where you could see the CapEx could potentially go, if you do decide not to go ahead with that program this year?

It's Tony here. I would say we're looking at contingency planning in all areas. So nothing's off the table but we've got contingency plans for additional Cardium drilling producers, as well as Alberta Viking inventory and PROP. All three oil-weighted areas will definitely have contingency plans put in place, just to provide us a bit of coverage in terms of commodity price in relation to gas.

It's more along the lines of we won't drill Manville because it's gassy, but we'll reallocate that capital to one of the other projects?

Definitely.

That CAD180 million is probably static.

Yes, that's correct. That would be the plan. I should be clear, that being said, we've done some sensitivity pricing on gas prices right now, and those Manville opportunities are still attractive. So we'll keep you posted as we go through the quarters here, and let you know what changes might come. But we're definitely going to steward to keeping the CAD180 million whole.

Great. One more question, if you don't mind. On the Alberta Viking you talked a little about changing up your completions. You talked about well rates 25% better than, quote, unquote industry number. I was just curious if you could elaborate a little bit as to what you're doing differently, and maybe what some of those rates are.

You bet. The biggest changes that we've done that we can tell, compared to industry activity in the area is that we are using full foam fracs in these wells. We're putting a bit of energy into the formation when we do the completions, gives us a little bit better flowbacks, and I think we're getting better sand clean-out initially.

In addition, we're also doing a clean out trip, just to ensure we've got the full well bore coming on production. So might be slightly higher capital to make that extra improvement, in terms of initial rates, but what we saw in these first 11 wells was these wells flowed for well over six weeks on initial production. Typically, industry offsets are running right top of the rods right off the hop.

These wells we're able to naturally gas lift, and we saw substantially higher oil rates. So in that 150 to 160 BOE per day range, and they're holding in flat. So out of that 11 well program, we're still holding in at about 1,500 BOE per day on those wells. So much higher than expectations.

What we did in terms of looking at competitor activity was to do a normalized plot, because the challenge there is there's a bunch of half milers in that program, and some longer wells, and we basically normalized those down to a one mile type curve, and then plotted our results over top of that, and come up with that 25% increase on competitor activity in the area. So all things being equal, our IP30s are definitely going to be higher, IP60s look encouraging, and IP90s are well on their way to exceeding our expectations.

That's great.

This is Dave. I think that curve is reflected in the new corporate presentation as well. If you take a look there, you'll see the basis against the existing industry curves.

That's great. Thank you.

There are no further questions at this time. I return the call to Mr. David French.

Thanks for all the questions, everyone. I've been really trying to put into context the difference in who the new Penn West is today to let's say, 10 years ago. There are the easy signals. Nearly 200,000 BOEs per day then versus 30,000 BOEs per day now. 25 floors of people down to 2.5, but that doesn't tell the whole story.

It is not a story of getting smaller. It's a story of getting stronger. Last year, we averaged 54,000 BOEs per day and finished the year with just over CAD180 million in funds flow from operations. This year, our 2017 business is expected to throw off more funds flow from operations than last year, on a basis of production that is 45% smaller.

That is the power of focus. It brings higher margins, competitive and disciplined operations in drilling, and the strength of a balanced, low decline oil weighted business. We're in a great place. Take care, everyone.

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