Vermilion Energy Inc.

Lorenzo Donadeo - CEO Tony Marino - President and COO

Travis Wood - TD Securities Kyle Preston - National Bank Nima Billou - Veritas Greg Pardy - RBC Capital Markets. Ray Kwan - BMO Capital Markets

Thank you, Connor. Good morning, ladies and gentlemen, and thank you for joining us today.

I am Lorenzo Donadeo, CEO of Vermilion. Joining me today are Tony Marino, President and COO; Curtis Hicks, Executive Vice President and CFO; and Dean Morrison, our Director of Investor Relations.

Please refer to the advisory regarding forward-looking statements contained in today's news release. These advisories describe the forward-looking information, non-GAAP measures, and oil and gas terms referred to today and outline the risk factors and assumptions relevant to this discussion.

This morning, we announced a record annual production of 54,922 BOE per day for 2015, an increase of 11% compared to 2014. Strong operational execution allowed us to achieve this record production, despite a nearly 4,000 BOE per day shortfall and anticipated Corrib volumes associated with regulatory delays, and a 30% decrease in exploration and development capital spending as compared to the prior-year.

Annual fund flows from operations was $516.2 million or $4.71 per basic share in 2015, as compared to $804.9 million or $7.63 per basic share in 2014. Higher production during the year, partially offset the impact of a nearly 50% drop in oil prices.

Fourth quarter fund flows from operations was $1.22 per basic share, beating analysts’ consensus of $1.11 per share by 10%. This month - this morning, we also released the details of our reserves and resource evaluations for 2015.

As reported both proved and proved plus probable or 2P reserves by 6% in 2015 to 161 million BOE and 261 million BOE, respectively. At the 2P level, we successfully replaced 170% of 2015 production adding 34 million BOE of 2P reserves.

30.5 million BOE or 90% of this growth came from exploration and development activities, with the remaining 3.5 million BOE coming from acquisitions. Our 2P finding and development costs including future development costs or FDC, decreased by 48% to $8.98 per BOE, while 2P finding, development and acquisition costs, including FDC, decreased 55% to $10.03 per BOE.

Despite lower netbacks in 2015, the significant decrease in finding and development costs generated an operating recycle ratio of 3.6x for 2015 versus 3.2x in 2014. Our fully burdened after-tax cash based recycle ratio also remains strong at 2.9x.

This demonstrates our ability to not only maintain, but improve our high level of investment efficiency in 2015, despite the decline in commodity prices. Our 2015 reserves report was supplemented with an evaluation by GLJ of our contingent resources in the Development Pending category.

The low best and high estimates of our contingent resources in the Development Pending category are 95.1 million BOE, 160.7 million BOE and 254.7 million BOE, respectively. Approximately 80% of our best estimate contingent resources reside in the Development Pending category, reflecting the high-quality nature of our contingent resource base.

While we have been faced with depressed commodity prices and significant volatility, the three key tenets of our long-term strategy remain intact. These guiding principles have allowed Vermilion to weather the many highs and lows experienced during several challenging business cycles over the past two decades.

They underpin the sustainability of our business model, our strong position in the industry and our track record of outperformance. The three key priorities encapsulated within our long-term strategy in order of importance are: first and foremost, the ongoing preservation of our balance sheet strength; second, to the deliver a reliable income stream to investors; and third, to invest in our business to fund production growth.

We've always maintained a disciplined balance sheet, yet it is during challenging market conditions such as today when the value of prioritizing the strong balance sheet becomes truly evident. During the year, we expanded our credit facility by $500 million to $2 billion, and extended the term to May 2019.

As of year-end 2015, we had approximately $840 million of available credit on our bank line, which allowed us to retire the $225 million of secured - senior unsecured notes, which came due earlier this month. In a further step to preserve our balance sheet, we amended our existing dividend reinvestment plan to include a premium dividend component in early 2015.

The premium dividend, which we view as a short-term measure, in response to the commodity environment, offers considerable flexibility and expands our access to the lowest cost form of equity capital available. We are able to suspend or prorate the program at our discretion at any time.

Our intention is to reduce and ultimately eliminate the premium dividend component when commodity prices recover. Hedging is one of the means we use to increase the stability of our revenues and fund flows from operations.

Decreasing volatility, assist in the planning of capital programs and helps to ensure strong project economics. Through a portfolio of callers and swaps, we typically hedge 12 to 18 months forward, but we currently have European gas contracts hedged up to 36 months forward.

In total, we have 25% of our 2016 net of royalty production hedged, including 44% of our anticipated natural gas volumes. Cost reduction is another means we use to help preserve balance sheet strength and increase fund flows.

Through our profitability enhancement plan or PEP initiative, we have realized nearly $90 million of cost savings associated with capital spending, operating expense and G&A savings for the full-year of 2015. Vermillion is unique among our peers and that we have never reduced the dividend since it was initiated in 2003.

The commodity downturn has been longer and more pronounced that we anticipated when it began in mid-2014, and as a result, many companies have discontinued their dividends. At Vermilion, we believe the dividends and income model remains a well suited to our asset base and that our existing dividend remains manageable with the actions we've taken to-date.

We remain committed to, first, prioritizing our balance sheet and preserving our financial flexibility, and to do so, we constantly monitor our dividend and accompanying capital program taking into account prevailing and expected commodity prices. Our objective is that funds from operations under the commodity strip will approximately balance or exceed our cash flows for net dividends and capital expenditures.

Should commodity conditions arise, under which, we can no longer expect to balance outflows and inflows over longer period of times, we would protect our balance sheet through further modifications of our capital investments, and if required, dividend programs. In November, we announced preliminary 2016 capital expenditure guidance of $350 million.

In January, we adjusted our 2016 capital expenditure guidance to $285 million and modest readjusted corresponding production guidance to 62,500 to 63,500 BOE per day. This morning, we announced a further revision to our 2016 capital expenditure guidance to $235 million, as a result of continued commodity price deterioration.

The $50 million reduction primarily reflects lower expected non-operated drilling activity in Canada, fewer workovers in France and a deferral of our Netherlands drilling and pipeline twinning programs. We have maintained the flexibility in our program to restore certain projects, should commodity prices improve.

Despite the significant reduction in planned capital expenditures, our 2015 production guidance of 62,500 to 63,500 BOE per day remains intact and represents growth of more than 10% year-over-year with the modest impact expected in 2016 from the most recent reduction in capital. Our Canadian operational plans for 2016, much like 2015, reflects reduced activity levels as we seek to preserve our financial flexibility and balance sheet strength.

Canadian activities in 2016, will be limited to expiry wells to maintain the net asset value of our land base and capital commitments on non-operated wells. In 2016, we expect to drill or participate in six gross or four net Mannville wells and six gross 5.5 net Midale oil wells.

Following on our entry into the Powder River basin in the United States in 2014, we increased our interest in that Turner Sand play to 100% through the acquisition in 2015 of our partner’s 30% working interest. Now with full control across a significant block of land, we see the Turner Sand play as an opportunity offering strong promise, where we can leverage our horizontal development expertise when prices improve.

We plan to drill one expiry-driven well in 2016 and complete two others in the Powder River basin. Moving over to Europe.

In 2015, we conducted our third annual drilling campaign in the Champotran field, achieving 100% success across the 13 wells drilled to-date. Incorporating the impact of our improving waterflood program, our 2015 development program delivered incremental exit production of approximately 1,000 BOE per day.

Our 2016 planned activity in France will be centered around highly economic workovers and optimization projects. In the Netherlands, we drilled two gross or 1.9 net wells and tied in one gross or 0.45 net wells in 2015.

These three successful wells added meaningful production leading to record volumes in the Netherlands for both the fourth quarter and full-year 2015. With the latest reduction in 2016 capital, the drilling program and line twinning project in the Netherlands are deferred, but we continue with the optimization of existing assets.

In July 2015, we entered into a farm-in agreement that provides us with participating interest in 19 onshore exploration, spanning approximately 850,000 acres in north-west Germany as well as associated proprietary data. During the exploration phase, Vermilion will assume operatorship for 11 of the 19 wells.

In 2016, activity will be focused on permitting and pre-drill activities for the Burgmoor Z5 well and two exploration projects. In addition, we will continue our ongoing analysis of the geologic and geophysical data acquired with the farm-in assets.

More recently, we were awarded two additional exploration licenses in Germany, adding approximately 110,000 net acres to our land position. Following the receipt of final regulatory approval, the Corrib project in Ireland began first gas production on December 30, 2015.

Initially, one well was placed on production, with the second well brought online early in January 2016. To-date, Corrib has been producing in line with expectations and well deliverability has been better than anticipated and there has been no significant downtime events.

Current production levels are approximately 33 million cubic feet per day or 5,500 BOEs per day net to Vermilion. We anticipate production levels for Corrib to rise over a period of approximately six months to peak production estimated at 58 million cubic feet per day or approximately 9,700 BOE per day, net to our interest.

Corrib is expected to be a significant driver of our production growth in 2016 and anticipated to meaningfully contribute to free cash flow. In Australia, we drilled and placed on production horizontal sidetrack well in the fourth quarter.

The well has exhibited strong performance over the six weeks of 2015, producing approximately 3,900 barrels per day. Offshore drilling in Australia requires a great deal of advance contracting and logistical planning, which means that full cycle costs are minimized by proceeding with our previously planned two well sidetrack program in 2016, despite current oil price weakness.

Furthermore, we expect more services cost to be near their lows in 2016 at the time of drilling, making this a desirable time to drill these high-quality sidetrack locations. Strong governance is paramount to Vermilion’s success and takes on even greater importance during times of uncertainty.

Recognition of our commitment to the highest standards of corporate governance, leading financial practices, and open investor communication is demonstrated to our recent receipt of TopGun status for Board, CEO and CFO level achievement from the Brendan Wood’s International Shareholder Confidence panel. The voting panel comprised of over 500 investors and sell-side professionals considered a short list of 323 potential nominees in Canada, of whom, less than 10% were rewarded the TopGun status.

In 2015, we were also ranked second within the energy sector and 20th among 234 companies in the Globe & Mail Board Games report on governance. We have also been recognized for our sustainability efforts in 2015.

We were named to the CDP Climate Disclosure Leadership Index, recognizing that depth and quality of our climate-related disclosure as compared to the 200 largest companies listed on the TSX. To be named to the Leadership Index, a company must have a disclosure score within the top 10% of surveyed companies.

In addition, we were the top ranking oil and gas company on the Corporate Knights Future 40 Responsible Corporate Leaders in Canada List, as well as being named the Top International Producer of the year by Explorers and Producers Association of Canada. These accolades reflect our continued focus on achieving robust performance for all of our stakeholders.

Despite the headwinds caused by the current business environment, we believe that Vermilion has a necessary - has taken the necessary actions to address market conditions. With our diversified portfolio and operational excellence, we believe that we can continue to deliver long-term value by focusing on our key priorities, protecting the balance sheet, providing a reliable income stream to investors and growing production in the long-term.

Our interests are well aligned with investors, with management and directors holding approximately 6% of Vermilion’s outstanding shares. As was announced in November, I will be retiring as CEO effective tomorrow, at which time, I will become Chair of the Board of Directors.

Since co-founding the company 22 years ago, we've achieved a great success and it's been an exciting and personally rewarding experience. And I'd like to thank our staff, our executive team, our Board of Directors and our shareholders for their contributions and support over the years.

With my retirement, there are a number of other organizational changes, Larry Macdonald, the current Chair of the Board of Directors, will transition to the newly created role of Lead Director. Tony Marino currently President and COO will assume the role of President and CEO.

Mike Kaluza, currently the VP of our Canadian business unit, will take over as Executive Vice president and COO. Vermilion is well positioned with the diversified high-quality asset base, a deep drilling inventory, a talented workforce and a strong corporate culture.

I look forward to working even more closely with the Board of Directors in my new role, and with Tony Marino and the entire executive team at Vermilion, as we look to take our company to new and exciting heights. With that, I will conclude my formal remarks.

And operator, please open the floor to questions.

Yes, good morning guys. Just some questions on the dividend and the capital program as we look out in this, we’ll call it, $35 oil price environment.

When you talk about balancing the cash flows, what other metrics are you looking at in terms of keeping the liquidity and the leverage position intact as you look to move capital or the dividends in this lower for longer environment?

Thanks Travis. Yes, I mean, I think the thing that we are really focused on is maintaining, first of all, our financial flexibility.

As you see, we've got considerable financial flexibility with our available bank line that's unutilized at this point in time. The other thing that we are doing is we are adjusting our capital spending, so that we stay pretty close to about a 100% payout net of the dividends.

And so really those would probably be the two primary factors that we look at. The debt to cash flow is moving up like in line with most of our peers, maybe a little bit lower than some of the peers.

And although we are not comfortable at those levels, I think that they are manageable, because we don't believe that oil prices are sustainable at this level and so we are really just focused on minimizing any incremental debt that we put on the balance sheet. We always say that we really don't have a debt to cash flow problem.

We have a cash flow problem, not a debt problem, and because we really do believe that oil prices will strengthen going forward and we think we can manage our debt levels under that type of a scenario.

Okay. So safe to say that you're targeting - of the outputs, you're targeting to keep the payout at a 100%?

Yes, and I think if we were to look at any acquisitions that were larger in size, then we'd always have to look at what kind of cash flow that brings to the company and how it all fits in with the overall debt levels.

Okay. Thank you very much.

Yes. Thanks Travis.

Yes, thank you. Good morning guys.

Congratulations on a good quarter in this challenging environment here. Just got a couple of questions for you.

The first one on these two sidetrack wells you're going to drill in Australia. I guess, you are planning to do that in Q2.

What kind of - are you expecting similar rates for this last well you just drilled, and also will you look to manage that production between the 6,000 and 8,000 or potentially produce above that?

Yes, Kyle, the answer to both of your questions is, yes, we'll have probably quite high productivity out of each of the next two wells. The exact rates are a little bit hard to predict, but dating back to the ‘13 program and including the well that we drilled last year, we've always had rates that are in the 4,000-plus barrel a day range for a well on - putting the wells on production.

The second ,question we would look to manage that production and probably keep it in the range of the mid-point that you talked about, somewhere in the range of 7,000 barrels per day would be our expectation for this year. So we would be husbanding some productivity that we could apply in future years to maintain flat to growing profile out of Australia ensure that we can supply the market for this valuable crude over the long-term and probably not have to apply very much capital in the next couple of years if we are in fact able to get the types of wells that we have drilled over the recent past.

Okay, great. Thanks for that.

And just another question here, just on Corrib. Once we had Corrib up and running at capacity, what does your operating cost profile look like there?

And then just related question, what's your view on European gas prices going forward?

Okay. On the first one, what would Corrib OpEx look like?

It's going to be a relatively low OpEx property. We are just in the early phases of collecting actual operating data, but we do believe that an OpEx of around $1 dollar Canadian per MCF is a reasonable level.

Perhaps it’ll start out a little bit higher than that, but we think over time it ought to trend to around a $1 or less. These are high productivity wells.

There shouldn't be a great deal of continuous maintenance activity, and therefore the unit OpEx should be pretty low. And that of course is going to lead to quite a high netback in the diverse market where we get pricing that is pretty close to national balancing point and where the fiscal regime established by contract has no royalties and we are tax-sheltered for some period of time.

Even beyond that - beyond that netback, we should see quite an excellent translation to free cash flow because we don't expect that much in the way of maintenance capital. So the project has been a long time coming, but we certainly do think we are going to see quite a significant contribution to FFO and really strong translation to free cash flow out of the property now that it’s on production.

With respect to European gas prices, they have declined quite a bit from where they were at a year ago. Currently reported in Canadian dollar terms, the two main markets in Europe for - that we report TTF in the Netherlands and the NDP in U.K.

are in the range of $6 to maybe $6.25 Canadian per MMbtu. That surprised that is a lot stronger than the one that we have in North America, but it is down a third or in fact a little bit more from where we were maybe a year ago.

That decline has been driven by several factors. One is that it was a very warm winter in Europe.

Second is that there is an expectation in the forward curve which is fairly flat at that price that there will be deliveries of LNG from the U.S. into the European market.

And thirdly, from some work that we've done in-house, we think that there is just a greater degree of correlation between European gas and crude oil and some of the other financial markets than had existed in the past, used to be that market completely had a mind of its own, but we are starting to observe this greater degree of correlation. And I think all three of these factors have led to the reduction in European gas prices.

This reduction actually isn't outside the realm of what we thought could happen. We do think that it probably represents something of the lower end that you would see in prices and that there is upside from here.

In our investors’ materials, we've outlined a couple of pages of explanation of what we see as the fundamentals in that market. And basically we see a market where probably supply and demand should be pretty well-balanced over the next few years and that includes even having significant deliveries of some of these stray cargoes of LNG from the U.S.

into Europe. We do think that longer term these European prices will not incentivize LNG built for the European market.

We think that that will take the something in the range of $8.50 Canadian per MMBtu or a higher price, and actually the prices that exist today will barely support the deliveries of these unassigned cargoes into the European market. Yes, it's economic to provide them, but not nearly as economic probably as the LNG companies had expected.

So for this and a variety of reasons, including switching from coal to gas and the U.K., which is already incentivized for the carbon floor and the potential for more coal to gas switching on the continent in the future, as presumably carbon floors continue to increase, we think that - it's fundamentally - it's a market that fundamentally supports the prize we have today and the forward curve reflects that. I would finally point out that we are quite significantly hedged for the European gas, 44% for 2016.

We have some long-term hedges that extend into 2017, and in fact into 2018. We think that the price that we get there today is an acceptable one from a standpoint of development activities for gas in Europe and also from a standpoint of our willingness to continue to hedge at this price, so we do remain moderately active in that market adding to this substantial hedge position that we already have in place.

So fundamentally we’re constructive on this market and we feel that pricing that we have can give us quite a lot of profitability.

All right. Great.

Thanks Tony. That’s it for me.

Thank you, Kyle.

Good morning. Just wondering how much longer - I mean, you’ve done a good job, and obviously, it's due to the investment in DRIP being able to reduce CapEx, but still maintain production guidance.

How much longer before this reduced investment starts to catch up with production volumes and where could you see that heading first? Obviously you’re constructive on prices recovering, so you'd want to increase investment in the future but should they stay low, when would we start to see the effects of this sort of reduced investment?

Yes, we have been able to - as you said Nima, we have been able to absorb quite a substantial reduction in capital and maintain the productivity in 2015 and into 2016 as well in our guidance. This is due to greater efficiency out of the projects.

Part of this is certainly due to the reduction in services prices, part of it we think is durable just in terms of learning curve, process improvements that we made on the cost side. And on top of that, we actually continued to get higher productivity both in our semi-convention development that we have in North America and in fact in the conventional assets in Europe and Australia as well.

So it's really, I would say, a broad-based improvement in the capital efficiency of the company, starting at already very strong levels but it in fact has moved up substantially over the last couple of years and that's reflected also in the FD&A cost and in the recycle ratios which have actually gone up for us in 2015 versus previous years. As we look ahead to 2017, we do expect a significant uptick in the average production from Corrib for the year, and that alone, probably in part something like a 5% or so increase to our company's production level.

And this is a nice structural advantage that we have in our ability to maintain rates, and in fact maintain growth even at lower capital levels. We haven't yet constructed the capital budget for 2017, and that will be a driver of how much production growth overall we are able to achieve.

I'd be hopeful that given the continued progress that we have made in cost and productivity that we'll continue broad-based growth in the company, but we'll actually have to look at the budgets as we approach ‘17 to be able to definitively give you an answer on that.

Appreciate the candor and the detail. Final question, you had mentioned that basically your funds flow would be balanced this year.

I just want to get an understanding, it would be balanced with CapEx and dividends, correct? Is that what you meant?

Yes.

Okay.

It would be basically cash flow net of our net dividends and net of DRIP and capital spending would be close to being balanced.

What commodity you had said more strip more, it sounded like current pricing. What commodity assumption feeds into that analysis broadly?

Is it $30, $35 oil?

Yes, it was at the - I think that was at our - the most recent strip pricing as of about a week ago. So I think it's somewhere around $35, $36 WTI.

Okay. You guys are doing a very good job managing your business under difficult commodity conditions.

Well, thank you.

My final question I would say is, where - when things do recover, where would be priority areas? Would it be - I guess, you probably more constructive on domestic light oil pricing and may be international gas pricing but where would the areas you’d first like to put money to work?

Yes. We actually have a really broad-based set of alternatives to invest in kind of during this low activity that we've begun in ‘15 and now to a greater degree in ‘16.

We actually find that we are able to advance a lot of these projects technically, and in terms of the expected economics cost levels and productivities such that we got a lot of choices. But let me list probably the top three places I think that we would go back to - three or four places that we would go back to in a moderately higher capital world.

And in so saying to, I want to point out that the required capital levels that we would have to have growth at our targets organically in the mid-single digits are probably a lot, lot lower than they have ever been in the past. So even a significantly increased organically growth rate would probably be done at quite a bit lower CapEx than you would have seen a couple of years ago.

But to list those projects in order, I think number one, we would resume Netherlands gas activity. Secondly, we would like to go back to the French light oil projects.

Thirdly, the Mannville project in west central Alberta has tremendous economics, even at the current prices, even at the quite low gas prices that we are seeing in Western Canada today and that's because there is so much condensate being produced, essentially at no discount to WTI out of those Mannville Wells that it alone can carry the economic before you ever account for the NGLs and the residue gas. And then fourthly, we'd like to see a resumption of more significant activity in the Turner Sand light oil price project in Wyoming.

This is all before we get to more activity in the Midale in southeast Sask where the economics have improved dramatically with way, way lower cost than we had at the time for the wells that we drilled and completed there versus what we had at the time that we made the entry at the southeast Sask a couple of years ago, that's before any activity in the Cardium, which has always been a very strong project and we have had - we have no drilling plan for ‘16 and only a little bit in ‘15, so there are a large number of strong Cardium wells alone that we could turn back to in resuming the program. And I’d say finally that this is completely without - this is completely ignoring the very significant dry gas opportunities that we've developed in west central Canada as well where we drilled some very, very strong amount of Notikewin wells that are capable of being economic even in the current environment.

Finally of course we'll have our ongoing planned activity in Germany for European gas under the very significant farm out that we did with ExxonMobil and Shell which closed at the beginning of this year. So I think there I probably listed seven or eight places that we can turn with the kind of an order of preference for the way we would attack those projects.

Yes. Thank you for listing them in priority.

That's a lot of good information you should be thinking ahead. Thanks for the information.

Yes, thank you.

Yes. Thanks.

Good morning. Tony, could you perhaps just touch on your Canadian gas volumes in the fourth quarter?

Really strong numbers there. And maybe just as a follow-up on your comments around CapEx.

I mean, from the sustaining CapEx standpoint now ex-Corrib, are we - is $235 million or $225 million now a pretty good number to think about going forward? Thanks very much.

Thank you, Greg. Let me take, first of all, your second question on the sustaining CapEx.

Your rough estimate of $235 million I think is not a bad one at all for the level required to stay flat, and of course, as we are talking about one of the previous questions, that is going to be way, way down from where it would have been a year ago or two years ago, even though the company has grown significantly in production volumes. So I would say somewhere in that range, perhaps a little bit more, perhaps a little bit less in the $235 million, but I think that is pretty close to a reasonable estimate.

With respect to your question about Canadian natural gas production in Q4, it was strong. It was strong for two reasons.

First of all, it was augmented by the well that I talked about earlier. We drill about a 13 million cubic-foot a day producer in the Notikewin in our Ferrier area which is kind of a new core area for us that we haven't talked about very much before, and two-mile my long multistage frac well that is probably one of the top few gas producing wells in Alberta.

It's an extremely productive area. We have a great deal of inventory in Ferrier.

At present, that well, like the other ones that we would drill probably over the next couple of years, there would be expiry-driven, it's not a place that we are putting very large amounts of capital in just because of lower gas prices that we have in Western Canada. Nonetheless those wells are actually quite economic at current prices just because of productivities are so high, the costs are coming down.

They are not really all that expensive to drill and complete. The other driver for the increase in gas production was just the residue volumes that we make as sort of a byproduct in the Mannville wells around 40% to 45% of the stream from those wells is hydrocarbon liquids and about three-quarters to 80% of that is condensate, but there still is a meaningful residue volume and well not really required for the economics of those wells, it is a saleable product, and as a result, it augments the cash flows and it's the other reason that you see a little bit higher natural gas production in North America in Q4.

Okay, great. And what did the Ferrier well cost you just D&C?

I think for that two-mile long Ferrier, which is - for the two-mile long Notikewin well at Ferrier, we are in the range of $5 million to drill and complete.

Okay. Thanks very much.

Yes. Hi guys.

Just on Corrib. Just wondering how many more wells are planned to be put on production before year-end and just for clarification for my sake, is the 5,500 BOEs a day that’s producing from Corrib, that’s net to you guys.

Is that still from two wells? And I guess, the last question on Corrib, and this is just purely out of curiosity is just, have you seen anything noticeable, or is it kind of in line with your expectations in terms of the water to gas ratios?

That's it for me.

Okay. In order, they are first how many wells are on, how many are left to bring on?

Two of the six are on. The rest will be brought on this year including the P2, which was last well to be made available and there is still a short flow line segment that has to be run to tie it into the subsea manifold next to the current Q2.

The second question, does that 5,500 BOE/d that we are currently producing net to our interest come from the just the two? That is correct.

And third question, are those rates in line with what we expected? They are very nearly exactly what we budgeted.

We would say that the productivity indexes from the wells that are on - the productivity indexes from the wells that are on are probably better - are certainly better than we expected. Secondly, we've been pleasantly surprised that there hasn't been any major source of downtime.

There is, as with any start-up, there is - there have been minor downtown items and that's why we are still on the budget, even though I would say the PIs are better than expected. Furthermore at present, well, the midstream utility is doing its integrity testing on the new segment of pipe that was put in for the project a few years ago, the top rates from the field are limited in any case, so you can't really take advantage of the better productivity right now.

The fourth question with respect to water gas ratios. I've not seen any report of water being produced yet from the field, so there is nothing to report there.

And in the two wells that are on right now, are they restricted whatsoever or is it just kind of on?

Yes, they are restricted.

Perfect. Thank you.

Great. Well, thank you, Connor.

Thank you everyone for participating in our conference call, and thank you all for your continued ongoing support.