Veren Inc (VRN) 2016 Q4 法說會逐字稿

Good morning, ladies and gentlemen. My name is Liz, and I will be your conference operator today. At this time, I would like to welcome everyone to Crescent Point Energy's fourth quarter and yearend 2016 conference call. (Operator Instructions)

This conference call is being recorded today, and will also be webcast on Crescent Point's website, but may not be recorded or rebroadcast without the express consent of Crescent Point Energy.

All amounts discussed today are in Canadian dollars unless otherwise stated. The complete financial statements and Management's Discussion and Analysis for the period ending December 31st, 2016, were announced this morning and are available on Crescent Point's website at www.CrescentPointEnergy.com, and on the SEDAR and EDGAR websites.

During the call, management may make projections or other forward-looking statements regarding future events or future financial performance. Actual performance, events, or results may differ materially.

Additional information or factors that could affect Crescent Point's operations or financial results are included in Crescent Point's most recent annual information form, which may be accessed through Crescent Point's website, the SEDAR website, the EDGAR website, or by contacting Crescent Point Energy.

Management also calls your attention to the forward-looking information and non-GAAP measures sections of the press release issued earlier today.

I would now like to turn the call over to Mr. Scott Saxberg, President and CEO. Please go ahead, Mr. Saxberg.

Thank you, Operator. I'd like to welcome everybody to our fourth-quarter and yearend conference call for 2016. With me is Ken LaMonte, Chief Financial Officer, Neil Smith, Chief Operating Officer, Trent Stangl, Senior Vice President of Investor Relations and Communications.

Before we begin, I'd like to take a minute to announce that Trent will be stepping down from Crescent Point in April of this year. Trent has been a valuable member of our team for the past 11 years and has provided strong leadership, hard work, and many contributions to the Company. He's a great friend, and I wish him well in his future endeavors.

Trent's responsibilities will be assumed by Brad Borggard, our Vice President of Corporate Planning and Investor Relations. Brad has been working alongside Trent since 2010, and was previously a top-ranked sales side analyst before coming to Crescent Point. I think he might have wrote that in there.

I'm confident that this transition will be seamless, given the strength of our team.

2016 was a successful year operationally. We exceeded our production targets on budget, increased drilling efficiencies, and developed new plays that more than replaced the wells we drilled in 2016.

We also added new reserves that replaced 137% of our annual production at top quartile F&D costs of CAD7.02 a barrel. This resulted in a recycle ratio of 3.2 times or over 4.5 times under current commodity prices.

And I'd just like to highlight as well, we spent CAD1.1 billion this year in achieving a 7-dollar 2-dollar (sic - CAD7.02 - see above) F&D is pretty amazing with that size of program.

Given that we've achieved these milestones during a volatile year in commodity prices, I think it's important to review our management team's execution plan during 2016.

At this time last year, our first quarter production was well ahead of budget and WTI prices were approximately $30. At that time, we made a strategic decision to defer CAD100 million of capital expenditures to the second half of the year.

This allowed us to further reduce costs and protect our balance sheet. This defensive plan allowed us to protect our average annual production volume of 165,000 barrels per day, while still fully funding our capital program and dividend at prices of $35 a barrel in 2016 at $45 a barrel in 2017.

Within our budget, we remained focused on long-term value creation initiatives versus just simply high-grading our drilling program. For example, we allocated CAD100 million through initiatives such as expanding our Flat Lake area through step-out drilling, testing the Castle Peak zone in Uinta for horizontal development. And we achieved extremely positive results highlighted by the CAD7.02 per BOE reserve add through these initiatives, adding over 1,000 net new drilling locations in 2016, bringing our total corporate drilling inventory to over 8,000 locations.

We also doubled our Tight Rock Waterflood programs and developed our ICD system, which has demonstrated encouraging results. Through our ICD pilot in late 2016, we were able to increase water injectivity and improve sweep efficiency.

We believe that this technological evolution is comparable to the advent of Isolated Packer Systems in 2006.

In September, we made the decision to raise CAD650 million in equity offering to reduce bank indebtedness. Given the commodity price uncertainty before the OPEC agreements to cut production and the U.S. election, we wanted to remove any downside risk to our balance sheet.

In 2016, we spent less than our funds flow from operations and achieved a total payout of 89%. We forecast 2017 guidance to generate a total payout ratio of 91% based on current strip prices.

We entered the fourth quarter with a strong balance sheet, and successfully executed our capital program, driving strong production and exit rate of over 167,000 BOEs per day. We also exceeded our [annual] average guidance in 2016.

We're very excited about 2017. We're focused on executing our organic growth plan, which is expected to generate exit-to-exit per share growth of 10%.

We have started the year in an excellent position and are currently ahead of our first quarter 2017 budget of 170,000 BOEs per day.

Similar to prior years, we plan to revisit our annual guidance post-spring breakout.

In addition to our growth plan, we are focused on improving our investor communications. We realize that communication around our recent financing could have been better and are make efforts to continue improving our overall investor engagement.

We spent a significant amount of time with our shareholders this past year and have listened and responded with several improvements to our compensation, governance, and corporate messaging.

We always welcome shareholder feedback and remain committed to maximizing returns to our shareholders.

I will now turn it over to Neil, who will discuss our operation highlights and 2016 reserves in more detail. Neil.

Great. Thanks, Scott. So as Scott touched on, we had a very successful year operationally in 2016.

Our reserves program generated 2P F&D costs of CAD7.02 per BOE, including changes in future development capital, one of the lowest in our history.

We achieved a top quartile recycle ratio of 3.2 times, based on an average corporate netback prior to hedging, of CAD22.18 per BOE in 2016.

This profitability measure demonstrates management's strategic capital allocation and the Company's high netback, high-quality asset base.

Our waterflood program continues to add incremental low-cost reserve additions. In 2016, we added 10.5 million barrels of 2P waterflood reserves, the largest annual addition in our history to date. These additions accounted for 16% of our total organic reserves growth in 2016.

This is the fourth consecutive year independent evaluators have recognized reserves attributed to waterflood, and brings our total waterflood reserves to over 23 million barrels since 2013.

As Scott mentioned, we continue to advance our waterflood technology. In late 2016, we piloted our new injection control device, or ICD technology. We achieved encouraging results, including increased water injectivity and improved sweep efficiency.

We have since begun installing additional ICD systems throughout our Williston Basin in southwestern Saskatchewan resource plays, and plan to have upwards of 50 systems installed by the end of the first half of this year.

We expect production data from these new installations by the second half of the year.

We have a consistent track record organic reserve additions and organic value creation through drilling and completions and our waterflood programs.

We have generated over 644 million BOEs of organic reserve additions since our inception. So to put this in perspective, this represents close to 70% of our current reserve space. These additions have doubled our required reserves through our organic drilling and completion in waterflood programs.

We expect to have future reserves growth, given our large oil-in-place assets. For example, if we increase recovery factors on a resource base of over 23 billion barrels by just 5%, this would equate to over one billion barrels of potential reserve [additions] and double are currently booked reserves.

In our Uinta Basin resource play, we drilled four one-mile horizontal wells during fourth quarter, each targeting the Castle Peak zone. Production results from wells completed to date continue to support our expected horizontal type curve. This curve generated a 90-day initial production rate of approximately 650 BOEs a day.

In 2017, we plan to drill a combination of 25 net one-mile and two-mile horizontal wells, up from nine one-mile horizontal wells last year.

We also plan to test new zones and new completion techniques within this program to further expand the play and improve upon the encouraging results seen to date.

During 2016, we improved our drilling efficiencies. By fourth quarter, our average drilling days in both the Williston Basin and Shaunavon resource play in southwest Saskatchewan, improved by approximately 11% compared to 2015.

To close, I'd like to thank our staff, especially our field staff during the winter months for their hard work and determination in delivering another successful year.

I'd also like to thank our suppliers for being tremendous partners through this past year.

Ken will now discuss financial highlights. Ken.

Thanks, Neil. In 2016, we generated CAD1.6 billion of funds flow from operations. We spent CAD1.4 billion, including capital expenditures and cash dividends, which resulted in a total payout ratio of 89%.

We continue to reduce our cost structure, as our annual operating costs of CAD11.27 per BOE were well below our initial budget of CAD12.25 per BOE, supporting strong 2016 netbacks of approximately CAD30 a BOE.

During the fourth quarter the Company reported a net loss of CAD510.6 million, due to an after-tax non-cash impairment charge of CAD457 million. This impairment only represents approximately 3% of our total assets as at December 31st, 2016, reflecting the high-quality nature of the Company's asset base.

This impairment does not impact the Company's funds flow from operations or the amount available under our credit facility.

The Company's fourth-quarter net loss also included an unrealized loss on derivatives related to changes in the futures market for commodity prices and foreign exchange. Excluding these and other non-cash items, our adjusted earnings from operations was a positive CAD100.6 million during the fourth quarter.

Through our 2016 equity financing, we lowered our net debt to funds flow from operations by more than 0.5 times. We continue to retain significant unutilized credit capacity of approximately CAD1.9 billion, with no material near-term debt maturities.

Since the third quarter of 2016, we have added approximately 11.8 million barrels of oil to our hedging program. Currently we have hedged 39% of our 2017 oil production at approximately CAD72 per barrel and 12% of the first half of 2018 production at approximately CAD74 a barrel.

As we enter 2017, we remain committed to maintaining a strong financial position and executing organic growth of 10% per share on an exit-to-exit basis.

I will now turn things back to Scott for some closing remarks.

Thanks, Ken. We had a strong operational year in 2016. We increased the long-term growth profile of the Company by expanding our new plays and adding new drilling locations to our inventory.

We also improved the long-term sustainability of the Company by improving drilling efficiencies, strengthening our balance sheet, and advancing new technology such as our ICD waterflood system.

We expect 2017 annual average production guidance of 172,000 BOEs a day, with exit production of 183,000 BOEs per day. This guidance has been risked for horizontal well production in the Uinta Basin and excludes any benefit from our ICD waterflood system.

Before opening up the line for questions, I'd like to thank our staff and our Board for their hard work and another successful year in 2016.

At this point, we're ready to answer questions from members of the investment community. Operator?

(Operator Instructions) We'll pause for a moment to compile the Q&A roster. Menno Hulshof with TD Securities.

So I have a question on your asset sale initiative. I understand that you won't comment on specifics. But since you haven't been a seller historically, maybe you could just talk us through how you're thinking about the process more generally and where the proceeds could get reinvested.

And then as a follow-up to that, should we expect strait-up dispositions or could you conceivably get more creative with JVs and spinouts?

No. I think basic, simple, non-core assets, smaller in nature within the Company that will either pay down debt or redeploy into our capital program and grow at a faster pace.

Okay so you couldn't really give us any sense of sort of target divestitures or anything like that, any comment regionally or by play?

As you know, we're a very focused company in Saskatchewan. And so it'd be the non-op, mostly non-op in nature-type assets that we've collected over the years, anywhere from CAD50 million to CAD100 million kind of size range. So we're pretty focused and use that money to pay down debt or reinvest it in the capital program.

Okay. Thanks a lot, Scott. That's it for me.

Patrick Bryden with Scotiabank.

Just wondering if you might be able to provide a sense for the second half response in this year and maybe going ahead from the ICD.

You'd mentioned that there's no benefit for those numbers in the annual guidance. So just want to get a feel if you have a sense for that.

Yes. I mean, just to give you a sense of magnitude, on our risked volumes for Uinta along, it roughly equates to about 3,000 barrels a day or 2% to our growth rate.

So exit-to-exit could be 12% 13% just with that one item alone.

On the ICD waterflood front, we're basically installing close to 50 injectors by the end of Q1. And the purpose there is to get that data sooner, to then make a decision midyear to further accelerate putting those systems in our other 300 or so injection wells.

And then from there, expanding and adding even more injectors. So it's key to us in Q1 to see those results.

And so because the system is sort of a six- to eight-month or six-month sort of response time, we'll have a good answer by the end of the summer to that.

Okay. And prior response times would have been 12 to 24 months or so?

Yes, 12 to 18 months.

Yes, okay. Great. Maybe if we can just flip back to the Uinta quickly. Just curious if you were to not be choking back on the wells in the first 90 days or so, or 30 days, is there a potential for greater volumes that we might be not seeing in the data right now?

Yes, for sure. I mean, these facilities that we put on are 2,000-barrel-a-day facilities.

Our next wells that we're completing in February are two-mile horizontals with larger fracs.

So ideally, those two-mile wells will even further outperform the one-mile wells that we're doing.

So we're continually evolving the results there. It's obviously very early stages on that play in that new play development. But we've moved, because of all the history we have in the past, we've moved to the two-mile horizontals, the newer technology, bigger fracs, and so these wells can produce in the thousands of barrels a day rate if we were to open them up full.

And so what we're reporting in the 90 days is a choked back production rate to keep a steady production flow and not to oversize facilities.

Great. And just, I'm not sure, maybe I don't understand it fully. But when you're having the combination of the one-milers and the two-milers, is there still sort of experimentation or are you saying the preference economically would be to gear more towards the two-milers, I think you were maybe implying.

Well, I think when you look at all the other plays throughout North America, the move is to two-mile horizontals because of efficiencies of cost, and then higher productivity and reserves per well.

Yes.

And so this would be similar in nature of doing that.

Yes. Okay. And just lastly, I appreciate the slides on the board renewal process. I know conversations with shareholders are obviously not something everybody's pretty two.

But as the Company kind of moves along on a path of maturation, can you give us any kind of elaboration on what those conversations in general might have been like and how they're adjusting your strategy going ahead?

You know what, I think one of the key slides that we added into our slide deck was like slide 27 on our employee engagement and integrity. And every year -- we've done this for 10 years. We've never ever put out this kind of information, never felt really the need to.

But I think it really highlights our management team and style that we have as a management team, that we do these surveys every year to our staff and we respond to the results and make positive changes.

And we're always open to improving the Company, trying to make us better and outperform year over year. And if you think back to all the different stages of our Company, from a junior to a trust company to a [div co], to now more senior producer, we've continually tried to evolve.

We realize we're not perfect and there's always room and things that we need to do to improve and be better and be stronger and try to be better, not only for our staff, but obviously for our shareholders.

And we've had a lot of conversations over this last year with our shareholders, taken a lot of their feedback, and responded and tried to be proactive.

And I think that's [live] kind of highlights, just the nature or style of our Company and I think how we are.

Great. Thanks very much. I do appreciate those slides. Those are very helpful. And thanks a lot.

(Operator Instructions) Thomas Matthews with AltaCorp.

I have three questions, but I figured I'd kind of start with the elephant in the room. I know you guys have been on blackout for the last few weeks and haven't addressed anything in public.

But I was wondering if you could comment potentially on the activism rumors that are circulating out there, if you've heard anything directly or kind of your thoughts surrounding that.

Yes. We always welcome feedback and engagement with our shareholders. And we have not had any, in our entire history, we've never had or been approached by an activist. So that's all I really can say to that.

We're pretty focused on doing things that we can control as a company, growing our business organically, focused on our new play development, and beating our numbers and beating our targets.

Okay. My next question is on the Uinta. I know that before when you were restricting some of these wells, if I recall correctly, it was just due to restrictions on the surface side on potentially the liquids handling or how big you were building the surface lease.

So when you do have a more robust program there, will that be addressed where you will see some bigger rates or is it just kind of restricting just to view how the type curve will behave and how the decline profile will look, or is a combination of both?

Yes, that's a good question. It's a combination of a lot of things. So as a company, in general, our goal, and this is through Saskatchewan and this has been for 16 years.

I'm a reservoir engineer. We always restrict our wells to manage, A, the cost of facilities and size of the facilities. So we never want to overbuild a facility just to produce for a rate for one month.

We see it as we don't want to damage the reservoir by overproducing. And so those kind of constraints are what we kind of build in.

In this play, it's all single well facilities and trucked volumes. And so our initial locations that we drilled on were vertical drilling locations that and we converted to horizontal. Our next drilling locations are now sized for horizontal wells.

And so that'll give us more flexibility to produce the wells at higher rate if we choose to, just because of the trucking volumes.

But in general, it's the combination of lower capital cost on the surface facility side and reservoir protection and management of our production.

Right. That makes sense. Maybe I'll ask a follow-up. On the down-spacing there, I know in the presentation it said that your horizontal inventory was just based on four wells a section.

But is that four wells just in the Castle Peak zone? And how does the other horizons obviously factor into that potential in that down-spacing?

Yes. So there are seven potential zones in this basin. And that location count is just for the Castle Peak over a fixed area, four wells per section. So it's early days.

Right. Right, yes. So there's lots of room to revise that number.

And then just finally on the waterflood, so the reserve bookings that you've been getting, they've been growing. But also, if you look backwards, the amount of convergence and CapEx spent on waterflood was also increasing over that time and so there's that lag.

Just wondering in 2017, now that you aren't doing new conversions, but you're using this new technique, will that pace of reserve engineer recognition slow or do you think the new technology will kind of keep that pace of waterflood reserve additions going into [2016], even though technically the pace of development isn't the same?

Yes. So it's a great question. Super highlight that I think we added 10 million barrels of reserves. We might have spent CAD100 million. What was the number? CAD50 million on waterflood. So that's CAD5 a barrel F&D on the waterflood.

That really highlights our corporate strategy as a company, which is small changes in the recovery factor create sustainability, long-term reserve adds value, significant underlying value.

And that's kind of what Neil said of the 5% change in recovery factor adds a billion barrels of reserves.

So we've barely scratched the surface of adding reserves. Those injectors every day inject water day after day after day, and every year the reserve analysts go back and look at our reserves and reevaluate the performance of those wells and give us reserve bookings, without spending any capital.

And so this just sort of highlights the momentum that's starting to build with our waterfloods and waterflood technology.

And the ICD technology accelerates the response of the production. Recovery factors, based on the simulation work we've done is basically around 33% is our latest. That's up from, I think 28% the last time we did our simulation runs with our historical matching.

And we see those numbers growing even further. But we've only booked as a company, I think in this area something like 8% to 10% of our recovery factor.

So we've got a lot of running room on reserve adds. So it's a great question we feel really highlights that success.

Perfect. That's it for me. Thanks, guys.

[Zane Shavik] with Mackenzie Investments.

Just one quick question. Could you help me understand why the production stream of CPG seems to be changing over time? In 2014, oil was about 86% of overall production and fell to, give or take, 80% in 2016. Gas production seems to have gone higher and it seems to be rising in 2017, based on guidance, if I understand that correctly.

Could you walk me through that a bit?

Like our liquids are up.

I meant oil specifically as opposed to liquids. NGL, their percentage of liquids have gone up significantly.

Zane, in southeast Saskatchewan, the Viewfield play, we have some of our volumes going through deep-cut plant. And so we are capturing more of the liquids out of that. And so you're just seeing that the liquids component, the natural gas liquids component is increasing relative to the overall level. That's really what's happening there.

All the plays that we're in are, the Viewfield Bakken, the Flat Lake, the Uinta Basin, all those plays have that same high oil percentage waiting, but they'll have a little bit of associated gas in there [with it].

Okay. Thank you.

Great. Well, thanks, everybody, for attending our fourth-quarter conference call. And thank you very much.

Thank you, ladies and gentlemen, for participating in Crescent Point Energy's 2016 fourth-quarter and yearend quarter conference call.

If you have more questions, you can call Crescent Point's Investor Relations department at 1-855-767-6923.

Thank you, and have a good day.