Enerplus Corp (ERF) 2010 Q4 法說會逐字稿

Good morning. My name is Stephanie and I will be your conference operator today.

At this time I would like to welcome everyone to the Enerplus Corporation 2010 year-end results conference call.

All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions). Jo-Anne Caza, Vice President, Corporate and Investor Relations, you may begin your conference.

Thank you, operator, and good morning, everyone. I would like to welcome you to the Enerplus's 2010 year-end results and conference call. Mr. Gordon Kerr, our President and CEO will be relaying our operational results and reserves information in greater detail as well as providing some additional color around our strategy going forward.

To help answer some of your questions at the end of the call today, we also have with us Mr. Rob Waters, our Senior Vice President and Chief Financial Officer. Mr. Rob Symonds, our Vice President of Canadian Operations; and on the line with us as well out of Denver, our President of US Operations, Dana Johnson.

Before we get started, please note that this call will contain forward-looking information. Listeners should understand the risks and limitations of this information and review our advisory on forward-looking information found at the end of the year-end news release issued this morning and included with our MD&A and financial statements which are filed on SEDAR and Edgar and available on our website at Enerplus.com.

Participants are also directed to our website for a replay of this call as well as other information on Enerplus. Investors may also call our toll-free investor line at one 1-800-319-6462.

All financial figures referenced during this conference call are in Canadian dollars unless otherwise specified and all conversions of natural gas to barrels of oil equivalent are done on a 6 to 1 conversion ratio. Following Gord's review, we will open the phone lines and answer any questions you may have. With that, I will turn it over to Gord.

Okay, well good morning, everyone. Thanks Jo-Anne. I would like to start this call with a few words regarding our strategic execution during 2010.

And then I'll get into our operational, financial and reserve results. Finally I will speak to what the path ahead looks like for Enerplus and then I will open up the call for questions.

I think as many of you are well aware over the past couple of years, Enerplus has been undergoing a significant transition to improve our focus and the competitiveness of our business, and also to position us to provide organic growth combined with an attractive yield to investors. Now through this transition, we sold approximately CAD900 million of non-core assets in 2010.

This includes over 10,000 BOE per day of conventional oil and gas production in our Kirby oil sands interest. And as a result of these sales, we believe we significantly improved the focus within our portfolio, lowered our operating costs and generated proceeds to position into assets with a better value proposition for our shareholders.

We have taken these proceeds and invested in new areas such as the Marcellus play in the Northeastern US where we now have over 70,000 net acres of operated land in addition to our 130,000 non-operated acres. We have also increased our positions in the Bakken through the acquisition of 75,000 net acres in North Dakota and another 155,000 net acres in Southeast Saskatchewan.

We have also added 80,000 net acres in the deep basin region of Alberta in British Columbia that is prospective for natural gas in the Montney and Mantle. In total, over the last two years, we spent approximately CAD1.3 billion acquiring close to 500,000 net acres of prospective land that we believe will provide us with future organic growth potential.

In fact, we captured over 60 million BOE of contingent resources associated with our North Dakota Bakken crude oil leases in 2010. We also now have almost 4 trillion cubic feet of contingent natural gas resources associated with our Marcellus leases, up 63% from a year ago.

On a total BOE basis, these contingent resources are over two times our current proved plus probable reserve base and include over 1000 unbooked future drilling locations. We have kept our balance sheet strong while we made these changes knowing that it would be essential to us in executing our development plans and unlocking the value in these plays. We believe we now have significant exposure to new growth plays that can help complement our portfolio of (inaudible) cash generating assets.

The opportunities we have captured will allow us to organically grow our production and reserves, and we are targeting a 10 to 15% growth in production over the next two years. So let's take a look at our results for 2010.

As an investment, Enerplus performed exceedingly well in 2010. Canadian investors saw a 35.6% total return and US investors saw a 43.4% total return reflecting the appreciation of the Canadian dollar throughout the year.

We met our annual production guidance, producing an average of just over 83,000 BOE a day in 2010. Our volumes were roughly 8000 BOE per day, lower than the average daily volumes in 2009. But you need to take into account the reduced capital spending in 2009 that impacted 2010 production and the sale of 10,400 BOE per day of non-core production in 2010.

Our exit production volumes were 77,200 BOE per day, 4% lower than our guidance. But this is primarily due to completion delays on two wells in North Dakota that we had originally expected to be on production in early December but didn't come on stream until the new year.

These wells are now on stream with initial production rates of 1500 barrels per day of crude oil per well. These wells are actually our best wells to date from this area.

Our development capital spending in 2010 increased over 80% when compared to 2009. We spent CAD543 million, 5% higher than our forecast of CAD515 million with approximately 50% related to oil projects mainly in the Bakken and our waterflood properties.

Just over half of our natural gas spending occurred in the Marcellus where we were focused on delineation and lease retention activities and drilling in the more prolific northeast area of Pennsylvania. Increases in drilling and completion costs in the Marcellus contributed to part of the increase in our full year capital program.

Spending on our Canadian natural gas assets declined throughout the year due to the low economic returns in the current commodity price environment. Because of long lead times for well completion and tie-ins in the Bakken and more particularly, the Marcellus, much of the capital spending in 2010 is just starting to generate production in cash flow in the current year.

In total, we drilled 225 net wells in 2010. Over 100 of these wells were supported by the Alberta drilling royalty credit program and the majority of these were shallow gas, about 104 net wells to us.

The majority of the remaining activity was focused on our oil assets, primarily the Bakken where we drilled about 29 net wells and waterfloods where we had about 47 net wells. We also drilled just over 13 net wells in the Marcellus.

Operating cost declined throughout 2010 averaging CAD9.54 per BOE, 6% better than our guidance of CAD10.20 per BOE in primarily as a result of the sale of high-cost non-core production and lower repairs, maintenance and electricity costs. We generated CAD703 million of cash flow from operations, down 9% from 2009, but again mainly due to lower production volumes as a result of our non-core sales.

We distributed CAD384 million to unitholders via monthly distributions representing 55% of cash flow from operating activities. And when distributions and development capital spending are combined, our adjusted payout ratio for 2010 was 132%.

And although we spent more than our cash flow in 2010, keep in mind that much of the capital spending in the Marcellus in North Dakota will not translate into production or cash flow until this year. In addition, we exited the year at a conservative debt to cash flow ratio of one times.

Our hedging programs helped to offset some of the weakness in natural gas prices. We realized hedging gains of roughly CAD50 million in 2010 with our natural gas contracts generating gains of CAD67.3 million while our crude oil contracts lost CAD17.6 million.

Looking at reserves, total proved plus probable Company interest reserves at year-end were 306.2 million barrel equivalent, down approximately 11% from year-end 2009. The sale of 34 million BOE of proved plus probable reserves associated with non-core properties represents approximately 60% of the reduction.

The remaining decrease in year-end reserves is attributable to the decreased outlook for natural gas prices and underperformance in a few properties. This resulted in negative revisions to our natural gas properties of 109 BCF and 2.6 million BOE associated with our crude oil properties for a total of 20.7 million BOE.

The majority of the negative revisions however were associated with our shallow gas assets. Roughly 40% or 45 Bcfe of our natural gas revisions related to the decline in natural gas price forecasts while 65 Bcfe related to performance mainly in our Shackleton shallow gas property where well interference has changed our view on long-term performance and economics.

The present value discounted at 10% of the performance writedown at Shackleton was approximately CAD100 million or 2% of our year-end proved plus probable reserves values discounted at 10%. Approximately 567 natural gas drilling locations were removed from our reserve report along with approximately CAD96 million of associated future development capital.

After these revisions, approximately 150 shallow gas drilling locations associated with our Shackleton property remain in our reserve report. Our 2010 development capital program delivered the highest level of reserve additions in our history replacing 114% of production before revisions. Our North Dakota Bakken and the Marcellus properties contributed the majority of additions with 11 million BOE and 87 Bcfe respectively.

Our finding and development costs in these areas our finding and development costs in these areas were CAD10.74 per BOE at Fort Berthold and CAD1.64 per Mcfe in the Marcellus. We also acquired 11.8 million BOE approved plus probable reserves in 2010, however, the majority of our acquisitions were of undeveloped land with only nominal associated reserves.

Our finding and development costs per BOE of proved plus probable reserves including future development costs was CAD17.46 per BOE before revisions with a recycle ratio of 1.6. This was due primarily to the positive reserve additions from our new growth properties in the Bakken and the Marcellus.

After accounting for the negative revisions primarily associated with our shallow natural gas assets, our proved plus probable F&D costs including future development capital was CAD36.71 per BOE with a recycle ratio of 0.75.

Our proved reserves represent more than 70% of our total 2P reserves and 53% of our 2P reserves are weighted to crude oil and natural gas liquids. I would now like to review our progress on specific asset areas starting with the Bakken.

In 2010 we added significant undeveloped acreage in North Dakota and Saskatchewan and now hold over 230,000 net acres of undeveloped land for this perspective for the Bakken as well as the Three Forks in certain areas. Total production from this resource play grew by 12% year over year mostly from our drilling activity in North Dakota.

In 2010 the majority of our drilling occurred in our US Bakken assets. To date our drilling results at Fort Berthold which exceeded our expectations and we're seeing payout on our long lateral wells in 15 months or less based on today's commodity prices.

We also drilled a number of wells in Saskatchewan targeting the Bakken on both our operated leases into our non-operated working interests at Taylorton. The drilling results on our operated leases have been disappointing.

Although we found oil in the Bakken formation, the limited amount was not sufficient to establish commerciality. We are in the process of evaluating the results of seismic data we have shot in the play area to determine what potential may still exist in the Bakken and other potential zones.

With our increased focus and spending, the oil waiting in our portfolio will increase going forward. We expect to spend approximately CAD300 million, almost half of our capital budget, on our Bakken oil properties in 2011.

Based upon the success of our drilling activities in Fort Berthold to date, CAD230 million has been targeted for this area as we move into the development phase. We plan to have three to four rigs working in North Dakota and expect to drill 32 net operated wells targeting the Bakken.

At least 75% of these wells will be long lateral horizontal wells. We're also planning to drill a few wells to test the Three Forks in this area.

Despite a very competitive business environment in North Dakota, we've been successful in securing service agreements for frac crews, proppants and a drilling rig under a longer-term contract to support the execution of our program. We're also working to have midstream agreements in place by midyear that will allow us to tie in our production and capture the associated natural gas.

We expect production at Fort Berthold will more than double as we exit 2011 with total production from our Bakken tight oil resource play areas growing by 50% through 2011, exiting in the range of 18,000 to 21,000 BOE per day. Keep in mind that given the highest initial productivity of these wells and the competition for services in this region, the exit production volumes and capital spending could vary from guidance. Depending on whether new wells are drilled and when their new wells are drilled, completed and tied in.

We'll be rounding out our Bakken tight oil spending with CAD70 million directed to Sleeping Giant in Montana and in our Canadian tight oil properties. Now turning to our water flood assets, our crude oil waterflood properties are a core part of our business and they are the largest part of our foundation asset base.

They provide [low decline] stable production and free cash flow to support investment in our new growth plays. This portfolio includes a variety of properties including from formations such as the Cardium, Viking, Radcliffe, Lloyd Minister and (inaudible) that offer new drilling opportunities, optimization and enhanced oil recovery potential.

Through horizontal drilling technology and reservoir depletion analysis, we have identified new opportunities in a number of these mature fields that we believe will help offset declines and in some areas provide a modest level of growth. Our activities in 2010 was focused on drilling recompletions and facility upgrades.

As a result of our land acquisitions in Saskatchewan, we expanded the potential at Freda in the Ratcliffe. We have drilled nine horizontal wells into the existing unit and expect that we have an additional 16 locations.

We're also turning our attention to other lands in the Radcliffe trend and believe that they will provide significant additional opportunities. We also started work on our first polymer pilot at Giltedge which will continue through 2011.

We expect to spend approximately CAD110 million on our waterflood assets in 2011, maintaining production volumes throughout the year at approximately 14,000 BOE per day. We will also continue to advance the work on our enhanced oil recovery pilot projects at Giltedge. A significant portion of this capital is being directed to activities we believe will position us for future production and reserve growth.

On the natural gas side, with weakening natural gas prices throughout 2011, we reduced spending on our Canadian natural gas assets. Over half of our natural gas spending was in the Marcellus where we were focused on delineation and lease retention activities and drilling in the more prolific northeast area of Pennsylvania.

We participated in the drilling of more than 120 gross wells in the Marcellus in 2010 about half of which were with our primary operating partner, Chief Oil and Gas, and the remainder with other non-operated partners in the region. We had planned to have 67 gross wells tied in during 2010.

However due to the timing of pipeline infrastructure and the availability of frac crews, only 38 gross wells were tied in. And despite these delays, we exited 2010 on track with production of approximately 91 million cubic feet per day gross of natural gas or 18 million cubic feet per day net to our account.

This success despite tie-in delays was attributable to better well results than we had originally planned. We are planning to spend CAD160 million in the Marcellus in 2011 mostly on our non-operated interests.

With our joint venture partners, we plan to have eight to 10 rigs working throughout the play in 2011 and expect to drill 150 gross wells. We also expect to complete approximately 120 wells and plan to have over 90 new wells on stream on joint interest lands by the end of the year.

In addition, we also plan to drill five gross operated delineation wells on our new Marcellus leases. Our Marcellus production in 2011 is expected to grow by 150% to approximately 45 million cubic feet per day by year end.

Now looking forward into 2011 and out into 2012, we expect capital spending to grow by 20% to CAD650 million in 2011 with about 85% of the spending on our Bakken, waterflood and Marcellus resource plays.

We have a select amount of spending planned for our Canadian natural gas assets. We plan to drill up to four delineation wells targeting the Mannville and the South Ansell area where other producers have had recent success.

Our shallow gas activities will consist only of recompletions at Shackleton targeting the multizone potential of the area. As a result of the decrease in spending in our tight and shallow gas resource plays, we expect production volumes from these plays will decline throughout 2011.

Given the longer lead time to production associated with the majority of our capital spending in the Marcellus and the Bakken, up to 40% of the production associated with our 2011 drilling program is not expected to come on stream until the remaining completion and tie-in capital is spent in 2012.

As a result of this spending, we expect the annual 2011 production to average between 78,000 to 80,000 BOE per day and to increase to 80,000 to 84,000 BOE per day by year-end. Production is expected to grow by 10 to 15% over the next two years, exiting 2012 in the range of 86,000 to 90,000 BOE per day.

Crude oil volumes are expected to increase approximately 20% over the next two years and crude oil and natural gas liquids are expected to represent just under 50% of total volumes by the end of 2012 up from 43% to date.

We do not have any specific plans to sell significant producing non-core properties in 2011, but we do expect to sell non-cash flow generating assets within our portfolio to help us preserve our financial flexibility. And examples of these types of assets would be our equity portfolio, small land positions scattered throughout Western Canada and also possibly a proportion of our non-operated Marcellus interest.

Based upon the current forward commodity price markets, we expect our debt to cash flow ratio to increase to two times in 2012 as a result of our capital spending plans and our dividend. So to conclude, Enerplus is delivering on its strategy.

We believe we performed well in 2010 and we have a strong future ahead. We've made significant strides in repositioning our asset base and now have meaningful growth opportunities in our portfolio including two of the top plays in North America.

We have line in sight to over 700 million BOE of contingent resources in our portfolio to date, more than double our crude plus probable reserves which we expect will provide us with significant growth potential in the coming years. Our performance in 2010 has built a stronger more focused Enerplus to deliver competitive long-term returns that include a balance between growth and income for investors.

Our focus going forward will continue to be on execution of our development opportunities and maximizing value for our shareholders. So with that, I will now turn the call back over to Stephanie, the operator, to take any questions from the audience.

(Operator Instructions) WB Robinson, Equity Pacific.

I tell you what; one thing that -- and I haven't had the opportunity to read your whole press release, and so forgive me if it's covered in there. But one thing that we are curious about, what is the hedging situation? In other words particularly with your oil projections in 2011 and 2012, what percentage of your oil is locked in on hedges?

We have about 58% of our oil hedged for 2011 right now. It is in the disclosure here, and then we started to position into 2012 and we have about 20% of our oil protected at the current time.

(Operator Instructions) Roger Serin, TD Newcrest Securities.

So could you give me an idea of whether there is any impact on some of the fracking legislation or proposed legislation on your Marcellus activity, Gord, just in terms of timing that?

I will tell you what. I'm going to let Dana Johnson address that. He is closer to it. Obviously there's a lot of discussion. But, Dana, would you mind commenting on the legislation that is coming or may be coming?

Just a brief comment, currently in the Marcellus as well as our other shale plays where hydraulic fracturing is key to establishing commercial production and reserves, the EPA in the US is launching a study -- this has been -- the issue has been studied before.

We anticipate it will be a multiyear pretty comprehensive study focused not just on the Marcellus but hydraulic fracturing in general. And based on prior results and the scientific panel in place, we believe we will have a good outcome with that. And the rigs across the US and Canada have protected groundwater sources over the years, tried-and-true technology, and we believe that the updated study will -- the findings will end up agreeing with prior studies.

And should I interpret from that then that you don't anticipate any additional impact on your activity levels at least at this point from any issues relating to water completion practices?

No, not at this point in time. Water access in the northeast, it's a well codified process. The Appalachian basin is one of the wettest basins in North America. The regulations require close attention to accounting for water volumes and we do so out of our permitted sources.

Okay, can I keep a couple more questions if you don't mind? On the North Dakota --

You have kind at the mic right now, Roger, so --.

I thought I could go ahead with that. North Dakota, takeaway capacity out of North Dakota, how are you guys set up as it relates to your proposed expansion from a production point of view relating to takeaway capacity?

Obviously there's some pressures in the area and right now we're doing a fair bit of trucking, and there are some proposals for new lines. But, Dana, why don't you expand on that again?

Yes, we have also contracted for some firm capacity out and continue to look at a number of options. I would say over the last few years, there have been -- with all the activity going on in the Williston basin, there are a number of new pipeline solutions and expansions coming to the table. But as Gord said, there is pressure there.

So in the short term, is this just impacting some of your transportation costs more than it is impacting your ability to sell product?

I think the short answer to that is yes although we have probably been delayed in delivering some of the product even. But we're working on the solutions. We're not I'd say, Roger, overly concerned about our ability to move our product.

Have you contracted for frac spreads in North Dakota?

Frac spreads?

Pressure pumping equipment.

We have entered in as I said into some agreements for frac services here over a mid to longer term, so a two to three year time frame for the frac services as well as the -- a drilling rig.

Roger, I don't think we have locked in the cost of the frac service.

Oh, yes, okay. But just access to them.

Correct.

Lastly, I am intrigued by your expanding footprint on sort of Western Canadian Montney lands, that kind of thing. Can you give us a little bit more background as to the play types you are pursuing, kind of timing of spending capital, what gas prices you think generally you need for those to go around?

Yes, I think that obviously we've got liquid rich gas potential that the economics go around much more readily. But I'm going to let Rob Symonds talk to our Western Canadian assets and the natural gas question.

Thanks, Roger. We have two additional plays that are in the portfolio that are mentioned. As you said, we have a Montney position which we've accumulated over the last couple of years.

The advantage of that portfolio is we don't need to drill it right now. So certainly the amount of capital being allocated to that play is low at this point in time.

The Montney assets themselves are in the Pink Mountain area of Northern BC. Industry is coming towards us in that area. We like the assets that we have, but we're in no hurry to do those.

The second area is the so-called Stacked Mannville more Central Alberta where again we've been accumulating acreage over the last year and a half or so. Again tenure is our friend here. We are not in a position that we have to drill it and as a result, we are again watching competitors who are around our land.

We are looking to spend some funds delineating this year. We have in fact drilled our first couple of wells in there, completion operations will be going on through breakup and beyond. And depending on results of that will determine how much additional capital that we will look to spend on this.

To your question on what does it take, I think a number of these plays with the liquids help that we believe is there have breakeven supply costs that are in the CAD4 range. That's not to say though that you want to necessarily drill them into the current gas market.

So we have the flexibility to spend additional funding if it makes sense to do so. But we're under no pressure to do that.

Okay, thanks very much. Gord, one last thing. I want to thank you. I like the consistency you've done in your presentation on play types, reserves, capital allocation, production, etc. It's very helpful.

Thanks, Roger.

Gordon Tait, BMO Capital Markets.

Just a couple of questions on some of your areas. I guess first in the Marcellus, you have been building up a presence there but I see that you're also looking to sell some properties in that area as well. Is it just the non-ops or are there certain parts of the Marcellus you want to exit from? What is your strategy there?

Well there is no -- first of all, it's a non-op situation that we would consider selling down a piece. We just acquired our operated acreage and we have no desire at this point to sell any of that.

I would say that it's a matter of we have got significant contingent resource potential there and it gives us I would say some flexibility on the financial side of things that if we see that we can take that capital and redeploy it and keep our balance sheet where we want it to be, that is an opportunity for us. We have got a significant non-op position as I said earlier of 130,000 net acres across the whole play area.

More than likely, there will be some targeted areas that we would look to if we look to sell or consolidated interest under. Time will tell how that will play out.

But it is something that we are keeping our eye on. Of course the interest continues to be quite strong in terms of that play area. You see more foreign players coming in who have long-term views in terms of where natural gas markets can move and certainly is an energy supply source even potentially off of North America.

Okay and then just in your -- you mentioned in your Saskatchewan properties specifically at Taylorton you are getting some disappointing results.

Not at Taylorton, no, that's not what I said. I said (multiple speakers) on our operated leases.

Operated leases, yeah. So is that -- are you just planning to go in and look at other zones or look at your drilling and completion techniques or is it something you think you might just eventually put on the table again?

Well as I said, right now we're working to evaluate a seismic program that we shot. When we acquired the acreage in Saskatchewan, we also gained rights to the Radcliffe.

Now we are having good success in the Radcliffe, so we see additional potential there outside the units boundaries where we have been drilling. But we also see other zone potential. Rob, do you want to add any comments to that?

Yes, Gord, I would just add one other thing. We certainly have encountered oil in the Bakken formation here but as you'll know, as you look at the Bakken in Saskatchewan and the water cut behavior across discovered field varies quite a lot including we've encountered higher water cuts than we need for economics.

With the seismic looking at the structure, we are going to need to go back and understand whether or not there's opportunities to get to some of those higher oil cut areas as others have been successful in other fields. So we're going to certainly be looking at that over the coming months. As Gord said, there are other zones that are associated with the acreage that we picked up and we will be looking at all of that in the months to come.

Okay, thanks.

Peter Norton, Norton Capital.

Just a question, if you would share with us the prospects for dividends looking forward, particularly vis-a-vis the rising levels of debt compared to cash flow.

Well I think we've been pretty clear that it is our intention to continue to pay out CAD0.18 per month in our dividend. We have also said that to the extent we receive the benefit of increased cash flows over time, we probably would direct more of the cash flow towards the reinvestment into the property base.

But we have also always said that we have to maintain a balance here and we have to keep our eye on where our debt levels are, what our capital requirements are and what our growth opportunities are in terms of where we direct the funds. But that's basically the message that we have provided to the market as our intention is to maintain our CAD0.18 per month dividend payment.

That remains at this point in time obviously.

We always [have to give you with] whatever happens in terms of commodity prices, production levels and other opportunities quite frankly. But that's our message.

Richard Roy, Citibank.

Just to follow up on that previous question. Just during your prepared comments you mentioned that your leverage would go from one to two times cash flow by the end of the year.

How would you look to pay down debt? Is this a situation where you're spending the money and over time as the production comes in, you'd use that cash flow to pay down? If you could just tell us how you expect to finance the program and also what is the maximum leverage you'd feel comfortable with?

Well first of all, we looked at our projections going out past 2012, we start to see additional cash flow generated that will reduce the debt to cash flow ratio below two times. Now again, a lot of things can happen over time.

But also I think I've indicated that we have some investments in our portfolio of assets that we would look to monetize as well as the interest in the Marcellus -- the non-operated interest could provide a source of funds. And so you know as we model it out, we are not I'd say uncomfortable with where we are headed in terms of a two times debt to cash flow ratio.

So that's I think the best I can tell you at this particular point in time. Do you think that two times is getting in the realm of uncomfortable? Yes, you know in our case, we don't want to go too far beyond that, and so we will just target toward that end.

Roger Serin, TD Securities.

I'm just waking up, sorry about that. One last question. Scale of the potential proceeds from your portfolio or equity portfolio, sort of what orders of magnitude are we talking about, Gord?

Well you know, probably one of the biggest investments we have in our portfolio is an investment in Laricina which is a -- Roger, you're well familiar with Laricina, I believe who are an in situ player who have been building a significant resource base, and we'll be watching that I think over the next couple of years. There's some very significant potential embedded in that stock.

We hold just over I think 4.4 million shares in Laricina, as an example of an equity investment. And then we have some non-cash flowing acreage situations that we would look to monetize. And in aggregate, we probably have a couple hundred million dollars quite frankly that we could move out of our portfolio of assets and not diminish our production profile reserves [and at] cash flow.

And the equity portfolio, I was aware of the Laricina, is there much else in there or is it predominantly Laricina?

The biggest one is Laricina, quite frankly, but we do have a handful of investments that we put in position over time. So they'd probably generate another, I don't know, CAD30 million, CAD40 million or CAD50 million.

That's what I was looking for. Thanks very much, Gordon.

You're welcome.

Deepinder Bhatia, private investor.

My questions are mostly around cash flow debt and they have been answered. The other marginal question here was to do with the production I guess impact from weather that you had in the fourth quarter of last year.

You said that it's now mostly up and running. Do you have any indication of what first quarter exit rate might look like based on the return to normal weather that you are seeing?

Well, I'm not sure if return to normal weather is quite accurate here, and it's pretty difficult to predict especially on a quarter basis exit rates and that, so I'm going to quite frankly not comment on that at this point.

Okay, no problem, thank you very much and good luck.

There are no further questions at this time.

Operator, thank you very much. Thank you to everyone who joined us on the call. I think we'll close off now.

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