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Executives

Shane Abel – VP Finance and Treasurer

David Fitzpatrick – President and CEO

Shona Mackenzie – VP, Engineering & Exploitation

Analysts

Gordon Douthat – Wells Fargo

Roger Serin – TD Securities

Steven Karpel – Credit Suisse

Andrew Peranick – Bastogne Capital

David Schumann – Northwest Capital

Jeremy McCrea – AltaCorp Capital

Lone Pine Resources, Inc. (LPR) Q4 2012 Earnings Call March 15, 2013 12:00 PM ET

Operator

Good day, ladies and gentlemen, and welcome to the Q4 2012 Lone Pine Resources Earnings Conference Call. My name is Mathew, and I will be your operator for today. At this time, all participants are in listen-only mode. We will conduct a question-and-answer session toward the end of this conference. (Operator Instructions) As a reminder, this call is being recorded for replay purposes.

And now, I would like to turn the call over to Mr. Shane Abel, Vice President of Finance. Please proceed sir.

Shane Abel

Thank you, Mathew, and welcome everyone to our fourth quarter 2012 earnings conference call. I am joined this morning by David Fitzpatrick, Interim Chief Executive Officer; and Shona Mackenzie, VP Engineering of Lone Pine. Before we begin, I encourage everyone to carefully review our cautionary language regarding forward-looking statements as well as the use of certain non-GAAP measures, those contained in yesterday’s press release as we will be referring to these things today. Also please note the quarterly results have been presented in Canadian dollars and on a net after royalty basis.

With that, I will turn the call over to David Fitzpatrick.

David Fitzpatrick

Well thank you, Shane, and good morning ladies and gentlemen, welcome to everyone joining us for today’s fourth quarter 2012 conference call. I appreciate the interest you are showing in Lone Pine and I look forward to this morning’s Q&A.

As this is my first quarterly conference call since becoming interim Chief Executive Officer two weeks ago, I maybe longer on strategy, tactics and execution yet shorter on operational details at this point. There has been a lot to absorb, but I am pleased, very pleased with what I’ve seen so far. I’ve had the chance to speak directly to many of you on the phone, but for those of you who haven’t had a chance to connect with yet, I look forward to meeting with you and sharing my view on Lone Pine’s upcoming successes over the coming weeks and months.

I have been involved with Lone Pine as a Director since the company’s IPO almost two years ago. And I’ve embraced my new role of interim Chief Executive Officer and look forward to adding my experience perspectives to the business and to then ultimately recruiting a top notch permanent Chief Executive Officer.

Let’s summarize our fourth quarter and year-end results before we commence a dialog. As outlined in the press release put out yesterday afternoon, the fourth quarter was an important quarter for Lone Pine as a strategic review that we kicked off in September really began to take shape. I’ll address those processes in a moment, but let me start by briefly discussing some of the operational elements of the fourth quarter.

Lone Pine’s Q4 net sales volumes were 70.6 million cubic feet equivalent per day with total liquids volumes in the third quarter of 3166 barrels per day. While these figures represent declines from the previous quarter, they reflect two major factors that were present. A disposition of certain natural gas related properties in the period, together with a slowing down of our capital program towards the end of the quarter as we completed our planned 2012 CapEx program.

Last year our net sales volumes came in at 83.3 million cubic feet equivalent per day which was in line with our guidance range we provided last August. Recall that Lone Pine made the decision this past summer, given the outlook for Canadian crude over the balance of ‘12 to come out of spring break with a single operated rig program at Evi and to execute on the second half 2012 CapEx program of $50 million to $65 million.

Much of this capital was completed in the third quarter of the year, so we only drilled four gross 2.8 net wells, completed five 4.3 net and brought on-stream five 4.3 net wells in the fourth quarter of last year, all of which were 39 degree light oil at Evi. For the full-year of ‘12 we drilled a total of 31.1 net wells, but 38.6 net on-stream. This pace of capital activity resulted in Q4 total capital expenditures of $15 million and full-year capital of $163 million, which was near the low-end of our corporate capital guidance range.

Last night, we released our first half 2013 capital budget and guidance. Our H1 ‘13 capital budget has been set at $35 million and that figure is designed to closely approximate our expected cash flow from operations, combined with proceeds from non-core dispositions in the period such that our debt level has kept relatively flat through the first half of this year. The reason we have provided only an interim budget at this time is that our strategic core asset review with our external financial advisors remains strong and ongoing.

We are going to focus on executing on this interim budget and then assess the second half of the year, when so called the dust settles. Lone Pine had one rig active in Q1 growing to total of six operated wells at Evi and participating in additional two gross one net non-operated wells. Remaining first half capital dollars are focused on bringing on the wells that we have already drilled as quick as we can before break up to support our growing production base and second quarter cash flow.

While somewhat conceptual at this point, we expect or anticipate the second half capital program when formalized to continue advancing our waterflood operations in the Evi area including a horizontal injection pilot and we’ll include some testing of the new venture lands we acquired in calendar 2012. We also released two sets of updated reserve figures yesterday, one, under the SEC methodology for our US investors, and one under the NI 51-101 methodology for our Canadian investors.

I will caution everyone that these two sets of reserve books are drastically different due to the reserve methodologies between the two. From an SEC standpoint, which is based on a backward looking trailing commodity price assumption, we like, many other natural gas liquid producers in the US, we’re faced with large price related natural gas revisions at this year as AECO used in the report fell from $3.77 in 2011 to $2.37 this year, that was ‘12.

For Lone Pine these revisions do not reflect our long-term plan to develop these natural gas assets, but SEC methodology requires to move those reserves to a contingent resource category. The net result of these revisions combined with property dispositions and other factors is a decline in our year-end reserves to 188 Bcfe. Backing out some of this noise, we have reported organic SEC drill-bit F&D costs of $2.42 per Mcfe and reserve replacement excluding revisions of 221%.

Switching borders to the Canadian side, our reserves ledger which uses an escalated forward-looking price set that we believe is more reflective of our reality, our proved plus probable reserves equated to 98 million boe at year-end ‘12. While down year-over-year due to dispositions, organic F&D was registered at $18.59 a boe and we replaced a 195% of our production of continuing properties.

All things considered, I believe we’re pretty pleased with our reserves for the year. Let’s shift gears. I will turn it back over to Shane to discuss the financial highlights.

Shane Abel

Thanks Dave. As David mentioned, while the fourth quarter of 2012 was a little slower from an operational perspective, we still posted positive financial results and executed on a couple of key strategic dispositions as part of our de-leveraging initiatives.

In the fourth quarter, we saw slightly higher crude oil prices as the increase in Edmonton Light prices more than offset the decline in WTI as the widely quoted Canadian crude differentials compressed considerably in the quarter. That differential averaged a little over $1 per barrel in the quarter compared to $8.50 in the prior quarter. This quarter-over-quarter change highlights the volatility we’ve seen in Canadian crude pricing over the year and in fact this differential has widened once again in 2013.

On the natural gas side of the world, we saw continued upward momentum in natural gas prices over the quarter to spot prices near $4 per MMBtu, a level not seen in well over a year. And in fact this morning we’ve rallied back at that price level again which is very encouraging. While prices have tapered off a bit towards the end of the quarter and earlier in Q1, we still enjoyed a 20% increase in the average natural gas price over the fourth quarter.

As a result of this strong commodity price factor, Lone Pine’s average realized price after hedging in the quarter increased 12% from $6.11 in the third quarter to $6.83 per Mcf in the fourth quarter. This rate is the highest average realized price we have seen since our IPO two years ago. From a cost perspective, Lone Pine’s third quarter production expense increased to $2.32 per Mcfe, which was an increase of 8% from the previous quarter.

Costs were up quarter-over-quarter as reduced overall volumes combined with a disposition of certain low cost properties have driven up that per unit cost. We continue to work diligently to focus our efforts on reducing operating costs particularly in Evi as these costs are a key driver to our margins in 2013.

In total, Lone Pine generated adjusted EBITDA of $25.4 million in the fourth quarter which was down 6% from the previous quarter. Adjusted discretionary cash flow came in at $16 million while we incurred an adjusted net loss of $11.6 million in the quarter. For the full-year, Lone Pine generated $106 million of EBITDA and $76 million of adjusted discretionary cash flow.

Turning to the balance sheet, we made great progress in Q4 at reducing our debt balance through a non-core disposition that generated nearly $100 million of proceeds in the quarter. Outstanding long-term debt at the end of Q4 stood at $347 million which was a 19% reduction from the $427 million outstanding at September 30. This current debt balance is comprised of $200 million of senior notes, which we issued earlier in 2012 and a $148 million of outstanding borrowings under our credit facility.

Our borrowing base at the end of the quarter was $275 million, and our next borrowing base re-determination is scheduled for next month. In advance of this upcoming re-determination, we have been working with our key lenders to provide an amendment to our current financial covenant which currently limits our debt to last 12 month’s EBITDA to four times. This covenant is currently limiting our liquidity and effectively capping our borrowing capacity at a number well below what the borrowing base would otherwise provide.

While we can make no assurance that through the success of this effort, we are hopeful we will have a constructive results in conjunction with the re-determination. We will provide an update to everyone on this process in April when it is concluded. I will touch very briefly on risk management before I turn things back to David. In the fourth quarter, we realized a total hedging gain of $7.6 million or $1.17 per Mcfe. While approximately half of these gain is related to our strong natural gas hedges for 2012 that have now fallen off the books, the company remains well hedged in 2013 with oil hedges in place at an average price of nearly $100 per barrel. The full details of our hedging is contained in our 10-K that was filed yesterday.

With that I’ll turn it back to David for closing remarks.

David Fitzpatrick

Thank you, Shane. While we have made some difficult decisions recently, I believe the company is pointing in the right direction. On a person note, David Anderson and Ed Bereznicki, our top quality executives and professionals who dedicated 100% of their energy and experience to Lone Pine. Sufficed to say, the Lone Pine Board shows a different set of eyes to move the Corp forward.

We are confident in our strategy and are focused on the end goal here at Lone Pine of reducing leverage in a prudent and value enhancing way. I believe – we believe in the value of the assets and are doing everything we can to extract that value and deliver it in the form of shareholder returns. The strategic asset review process is my primary focus and we are confident we will have a positive conclusion to believe me this very intensive process.

We do have a few more steps to make as we turn this business around, but I am confident we have the assets and the team to make this work. We look forward to providing updates on our business over the coming months in the quarters and Mathew and staff here, we are now ready to take questions from our audience. Thanks very much.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Please standby for your first question. And your first question comes from the line of Gordon Douthat from Wells Fargo. Please proceed.

Gordon Douthat – Wells Fargo

Good morning everybody. My first question is on the strategic asset review process. Could you just – any color you can give us there on the remaining steps, and then what options you’re looking at as far as the balance sheet goes and how those two might be related?

David Fitzpatrick

Thank you, Gordon. It’s Dave here. I’ll comment on the strategic review process and provide some additional color on that by all means and then I’ll invite Shane to comment on any potential balance sheet implications of that.

It strikes me that a strategic review process such that Lone Pine has embarked upon is similar to my last home renovation in fact, where it takes a series of finding the right contractors, maybe an improper analogy but applied anyways, finding the right contractor, picking all your materials and then final negotiations in terms of getting the project done on time, on budget. And I am pleased to say that we are well advanced in that so called renovation. Based on my experience, so from my home may take a little longer than my wife and I would have loved to have seen. And so in a roundabout way Gordon, I’m trying to suggest to you that this is my highest priority. This is number one, two and three on my top three list.

We are very focused on it and we have a live issue that we are wrestling with to complete the home renovation process. I wish – I look forward to a time when I can be more specific. In terms of the financial implications and balance sheet I think we were clear in our prepared remarks, but I will invite Shane if he wants to share – shed any additional color to go ahead as well.

Shane Abel

Yes, so obviously right now, Gordon, we’re focused on the borrowing base re-determination which is coming up here in the next couple of weeks. Clearly a pressing issue as our credit facility currently sets as that four times trailing 12-months EBITDA covenant. We’re going to look to have that amended, expected the banks will work constructively with us.

Post that re-determination and post the potential transaction that comes out of the strategic review, it’s a bit unknown right now. It’s a little bit of a chicken and the egg, so we’re going to wait to see how this process materializes and what type of capital infusion that may provide to the business. And then we’ll deal with the remaining capital structure at that point.

Gordon Douthat – Wells Fargo

Okay. And then question for you David, as you kind of go through this process I know there is a bit of a transition going on, but is it your plan to stay in place as you kind of guide the company through these next steps and how long do you foresee that taking place?

David Fitzpatrick

The short direct answer is yes sir. I will stay in place until we’ve got some turnaround and the appropriate experienced permanent CEO is in place.

Gordon Douthat – Wells Fargo

Okay, I’ll stop there. Thanks.

David Fitzpatrick

Thanks, Gordon.

Operator

Thank you for your question. Your next question actually comes from the line of Roger Serin of TD Securities. Please proceed.

Roger Serin – TD Securities

Good morning everybody.

David Fitzpatrick

Hi Roger.

Roger Serin – TD Securities

Congratulations, David.

David Fitzpatrick

Thank you sir.

Roger Serin – TD Securities

Following up on your answer to your home renovation. So timeline from where we are today, are you expecting zero to six months, six to 12 months or longer than 12 months to move this a little bit more concretely forward?

David Fitzpatrick

Yes, I would have loved to have said we’d be in the house already a month ago to give you again a direct answer. And then obviously on the go-forward, I unfortunately can’t be any clear than to say it will certainly not be this week. So we’ll be back to you as quick as we can. I cannot wait till I am being able to be a little bit more specific, because I am excited about what we’re looking at.

Roger Serin – TD Securities

Okay. That’s good enough. Shane, debt-to-EBITDA, if you were to be restricted without the amendment, what sort of percentage impact would that have on your borrowing base orders of magnitude?

Shane Abel

Well our EBITDA for 2012 which is the current last 12 months period was $105 million. We have to take out the EBITDA contribution from major properties that we’ve divested in the period. So we have to take off $12 million from that amount for the Wild River disposition. So my math says that’s $93 million. The current four time covenant would get us to $372 million. We’ve got about $200 million of outstanding senior notes depending on the FX rate at the time.

So if that amendment were to be held constant at four times, our credit capacity would be about a $175 million. So our liquidity would be approximately $25 million based on current drawings [ph].

Roger Serin – TD Securities

Thank you. Exactly the detail I was looking for. We’ve been, I don’t want to say spending all night working on it, but spending some time trying to match to your net asset value calculation and we’ve had some challenges. So some of the questions that I am going to go through will highlight what we’re trying to do in terms of matching to your third-party reserve report. Can you give me some color on the negative technical revisions on both the oil and the gas side?

Shona Mackenzie

Sure. Roger, it’s Shona here. So on the technical revision, it’s a combination of changes in the type curve at Evi as well as the slowing of the planned pace of the development of our gas assets which now had been pushed out by kind of a couple of years based on the price that we’re using. And then the negative revision that obviously offset by the successful infill drilling results at Evi which were based on our eight and 10 well per section pilots that we completed in 2012.

Roger Serin – TD Securities

So today, or maybe you can give me a sense, what are you getting in terms of EURs for a type curve that you’ve got today for Evi or perhaps there is more than one type curve, give me a range, Shona?

Shona Mackenzie

Sure, so for US people who are listening, what I am talking about right now is the Canadian reserves. So on the NI 51-101 side of the world, our approved type curve at Evi is about 97,000 barrels and our P plus P type curve is a 133,000 barrels. The peak rate on those type curves is a 180 barrels a day, and the 30-day IP is 145.

Roger Serin – TD Securities

Perfect. And that looks pretty similar to what I saw last night when we pulled the data. Can you give me a sense of how many reserves are booked now, Slave Point reserves are booked at EVi in the reserve report, and how many will be drilled in ‘13?

Shona Mackenzie

Number of locations I’m assuming you’re talking about here?

Roger Serin – TD Securities

Yes, booked.

Shona Mackenzie

So the 2013 location in the reserve report is 26 gross wells and the total amount of P plus P undeveloped locations in our NI 51-101 report at Evi is 237.

Roger Serin – TD Securities

Okay. These are gross numbers, right, Shona?

Shona Mackenzie

Yes, these are all gross.

Roger Serin – TD Securities

Okay. When you look at your third-party reserve report, what you get to in terms of peak production rates, and if you could do that on a boe basis that would be great, and when that does occur roughly?

Shona Mackenzie

So our peak on a P plus P basis?

Roger Serin – TD Securities

Yes.

Shona Mackenzie

Is reached for the corporation in 2017. The peak oil is around 8,000 barrels per day and the peak gas is about a 100 million a day. I’ll let you do the math to put it into equivalence.

Roger Serin – TD Securities

Yes. No, I can divide it by six, perfect.

Shona Mackenzie

Yes, I figured you could.

Roger Serin – TD Securities

That’s about the full extent of my math capabilities, but so Slave Point horizontal injection moving to the pilot that you’re proposing for the second half of this year, you’ve been working on a vertical pilot from what we’ve seen the results look recently good in terms of response time. What does a horizontal get you, just the increased injectivity?

Shona Mackenzie

Yes, I mean the idea of the horizontal is obviously we’re developing that’s build with horizontal well. We’re not planning today and go a drill a bunch of vertical injectors. We’re planning to use some of those existing horizontals to be our injectors. And so really what we have to do is do a pilot to see what that’s going to yield for us, but the idea is obviously that we need to get more water into the ground to support the withdrawal from the horizontal producers.

Roger Serin – TD Securities

Okay. I believe that might be all of my questions. Thanks very much.

David Fitzpatrick

Thanks Roger.

Operator

Thank you for your questions. Your next question comes from the line of Steven Karpel of Credit Suisse. Please proceed.

Steven Karpel – Credit Suisse

Good morning guys.

David Fitzpatrick

Hi Steve, how are you?

Steven Karpel – Credit Suisse

Good. Can you first bridge me from the fourth quarter to your guidance on production, so I can understand how much is declined and how much is at each individual asset sale?

Shane Abel

Sure. So on the GAAP side as we’ve said in the last couple of quarters, the core remaining assets in Narraway/Ojay are experiencing about a 20% annualized decline. So that’s going to be about 5% per quarter. The change in gas volumes between Q4, once you take out Wild River which was a transaction that closed in late December, so those volumes were included almost in their entirety for Q4. We take out that 15 million a day and we decline the gas – the remaining gas in the Deep Basin to Narraway/Ojay by 5%, as well as take out the Harrington asset that we sold earlier in Q1, that should get you to that guidance number. And then on the oil side, as David said in the prepared remarks, brought on four wells in Q4, that’s production profile is now declining by about 35% on an annual rate.

So we’re going to see some declines on the oil side going into Q1 as we weren’t bringing on new volumes until very late in the first quarter, but we expect that oil volume at Evi to escalate into the second quarter to provide us with that provided guidance range from yesterday.

Steven Karpel – Credit Suisse

If I’m seeing this right, how much – remind me how much Harrington was?

Shane Abel

It’s about a million and a half a day.

Steven Karpel – Credit Suisse

So then what was the – what would be exit rate then?

Shane Abel

We don’t provide spot estimates, so just the quarterly figure is all I can provide, Steve.

Steven Karpel – Credit Suisse

Can you talk about, as you look at your – on the borrowing base just from the pure asset sales where – how much of the current volume base accounts for all of the asset sales that are done, meaning where should we start our number at I guess is the way to think about?

Shane Abel

So the $275 million borrowing base, it’s currently effective is post the Wild River disposition. The only subsequent disposition that would be backed out of that borrowing base value would be Harrington, which has a borrowing value of probably $5 million. So I think the starting point would be somewhere in that $270 million range and then obviously it’s going to be a negotiation between ourselves and our syndicated vendors as to what the appropriate revised bond [ph] may should be, and more importantly from our perspective is the relaxation in net covenant and as Dave has articulated that his number one, two and three priorities is the RBC process and the strategic review we have ongoing.

My priorities one through three is dealing with that credit facility and focusing on the balance sheet side of our business.

Steven Karpel – Credit Suisse

And if you considered other options aside from a traditional revolver (inaudible)?

Shane Abel

Yes, we have and there are numerous opportunities out there for alternative forms of capital. I think right now the most prudent approach for us to do is work constructively with our partners in our lending syndicate. We think that this is going to be an issue that we can have results here in our next re-determination, but clearly looking out longer term, our capital structure at it currently is comprised of the credit facility and the senior notes, probably need some re-tinkering and that’s definitely an issue that we’ll embark on following the conclusion of the strategic review.

Steven Karpel – Credit Suisse

And then two others ones, one just on the reserve side. Can you tell us what you think the – if I just take the reserves that you posted on looking out on SEC basis, I think there was about a $110 million, $112 million change and of that a decent amount of that was the sales. So if I take that portion out, I think I get a 210 excuse me – that would get me to a $150 million thereabouts, how much of that $150 million comes back under the current prices or NYMEX pricing where we are today NYMEX forward curve?

David Fitzpatrick

If I can just try and paraphrase your question while Shona is I’ll say checking her sheet notes here, you’re suggesting of course as we noted with the lower gas price from an SEC scenario, we converted a significant number of, call it BCS [ph] from to the – out of the total proven category. And you’re asking then with a revised improved natural gas price, basically today’s commodity prices what would we look to bring back in under a higher gas price scenario?

Steven Karpel – Credit Suisse

Right, what would you be able to book I suppose today, I mean maybe the simple way to ask is it a two-fold. The $131 million price related revisions under the current NYMEX deck, how much of that $131 million would come back? And then separately is to explain what the given effective revision number was decently large, what – to understand a little bit more what happened there?

Shona Mackenzie

Okay, so I’ll answer the first one on the gas side. Basically the current NYMEX prices that Shane had talked about that you’re seeing right now, those would mean the reinstatement of all our gas reserves in the SEC world. And that’s why in our Canadian world, you don’t see that magnitude of gas write-down because in the Canadian world with an escalating step which represents what we see today, those are there are still very balanced there. So that’s on the price related revision.

Steven Karpel – Credit Suisse

All the price related revisions would come back under current prices (inaudible).

Shona Mackenzie

Yes. Basically for us once you get kind of 350 to 370 NYMEX, those wells all become economic again under SEC rules. Now of course we can’t bring those reserves back until under SEC rules that constant trailing 12-months price to get to that point the step prices and relevant in the SEC world. So in the real world, they are not uneconomic I guess that’s the message.

And then on the technical revisions on the SEC side, it’s – when you take the pricing part out of it, the rest of it is really the same sort of answer, that I gave on the – to the Canadian reserve question. It’s to do with changes in the proved type curve at Evi. So the proved type curve at Evi is 997,000 barrels.

Steven Karpel – Credit Suisse

Understand. And then lastly for David, maybe just I don’t know if you will answer with a number, but obviously I would like you to is how much capital do you think the business needs incrementally from where we are today?

David Fitzpatrick

Well I guess an easier one to answer and I’ll take it on a broader context so we’ll start there. Approximately 19 months ago, when I was asked to look at joining the Lone Pine Board, I was fortunate to receive what I thought was an extremely thorough technical dog and pony show. And at the conclusion of that show, after looking at all the upside in the company, development upside, exploration upside, I decided to join the Board.

Fast forward to today, 20 some months later, clearly under a different natural gas regime but further to Shona’s point, much of that, call it optionality that is not in our stock price right now that fits in at least what I call here in Calgary a P3 category, will at some point represent very significant shareholder upside. We need to position this company to get to the point where that can be realized. And as a result, I had jumped back into the role here in an interim CEO position to help point this thing in the right direction. So that’s the broader picture, and I am very pleased to be able to react to that.

More specific, we have a decline rate on a light oil resource pool, consistent with most type reservoirs, that’s pretty steep. And so as result, we need to drill approximately 20 wells a year at Evi to stay flat, ballpark. I’m ballparking here. $3 million a well, I think my math suggests that’s about $60 million. The natural gas side of course has its declined as much shallower, much longer reserve light index on the natural gas side and it represents not the cash cal today that we wish we had clearly because of gas prices, but ultimately a tremendous cash cal under an inflated rising natural gas price.

I guess sufficed to say, we will work with our lending group, wrestle down the covenant issues, look to continue a longer term relationship with our financial partners and free up the capital to not only offset the clients as I’ve suggested with our oil drilling program at Evi, but ultimately position ourselves ultimately for an improved gas development economic scenario which will really launch this company forward.

Steven Karpel – Credit Suisse

Thank you guys.

David Fitzpatrick

Thanks Steve.

Operator

Thank you for your question. Your next question comes from the line of Andrew Peranick from Bastogne Capital. Please proceed.

Andrew Peranick – Bastogne Capital

Hi, thanks guys. Shane, I just wanted to follow-up on some of the comments you made about the credit facility. And the re-determination of the – excuse me, the re-determination of the borrowing base occurs next month in April, correct?

Shane Abel

Yes, it will be effective May 1. We’re actually having a lenders meeting next Thursday and then the lenders will work on their math for a couple of weeks. So we’d expect to have that resolved in early April.

Andrew Peranick – Bastogne Capital

Okay. And have you already begun negotiating with them on covenant relaxation or that will start next week at the meeting?

Shane Abel

We’ve been working in conjunction with our lead lender for quite some time discussing this matter, and we’ll be taking it to the rest of the syndicate at that bank meeting, but it won’t be coming as a surprise to any of our lending syndicate members. And again, based on our discussions with our lead lender, we feel pretty comfortable that we’ll have a constructive resolution.

Andrew Peranick – Bastogne Capital

Okay. I don’t know if you want to talk about this at all, but given kind of your guidance for debt staying flat for the first half of the year, have you – and then revisiting your capital plans subsequent to that and result from the strategic process, have you kind of targeted where you think you might want to have the covenant relaxation go to 4.5 times, 5 times and if you’ve thought at all about, what kind of rate bump it may cost you to get that?

Shane Abel

We’ve definitely thought about it, but we’ll keep that within this room here and we’ll let you know what the results are after that negotiation.

Andrew Peranick – Bastogne Capital

Okay, fair enough. And I just want to ask a question on vis-à-vis the bond and ventures. Is there a language in the bonds in terms of any kind of – is there a level of assets that are sold or as part of a JV that would require you to call back any of the bonds in the venture?

Shane Abel

Yes, it’s a pretty standard oil and gas venture, so it will have the customary language on any asset sale proceeds have to be reinvested in the business within 12 months, so obviously if we were to pursue any transaction as part of the strategic review those assets are clearly going back to the business, so we have no issue there. The noted venture also has a provision for the situation where you sell all the substantially all of the assets. We’re not going down that path so from a note venture perspective we don’t see any restrictions that limit our ability to execute any of our potential path on the strategic review.

Andrew Peranick – Bastogne Capital

Okay, thanks. Good luck.

David Fitzpatrick

Thanks Andrew.

Operator

Thank you. Next question comes from the line of Gordon Douthat of Wells Fargo. Please proceed.

Gordon Douthat – Wells Fargo

Yes, thanks for the follow-up. David, I think I just heard you say, well costs at Evi are at $3 million range, is that correct?

David Fitzpatrick

I believe I said approximately $3 million would be a grab number that would represent approximately 600 meter lateral what we call a short yes, and that $3 million is a tied-in cost.

Gordon Douthat – Wells Fargo

Okay. And then the other question I had, you mentioned kind of your preliminary plans for the second half of the year, I know you like to change between now and then, but you mentioned testing of a new venture opportunity. Any color you can provide there and then what’s the thought process behind testing that now versus just going after what you know you have in the Evi?

David Fitzpatrick

Thanks very much. It’s Dave here still. I will only suggest if it’s a evident from our capital expenditures, in fact last year in 2012, we spent approximately 10 point – I forget the decimal column, $10 million on undeveloped land. And I will only suggest that was a very concentrated land purchased It was not scattered and we are very pleased and again can’t wait to be able to discuss that venture because I think most of the land is tied up now in terms of a new venture, a new pool opportunities. And in due course, we again will be more specific in that regard.

Gordon Douthat – Wells Fargo

Thank you.

Operator

Thank you for your question. Your next question comes from the line of David Schumann [ph] of Northwest Capital. Please proceed.

David Schumann – Northwest Capital

Thank you both for your service to the company. Dave, my question is about the waterflood potential and ability to improve economics through secondary recovery. Could you talk a little bit about that, particularly giving your perspective with companies at the Slave Point?

David Fitzpatrick

Thank you, David. Again let me start broader and I’ll try and drill down as much as I can. On the Lone Pine lands at Evi, there is approximately 600 barrels of original oil in place, working interest share on the Lone Pine lands. And again don’t pin me on decimals here, let me talk more strategic. 600 million barrels and our primary recovery factor is 10% to 12%. So that I can do mental math here is I am talking to 10% of 600 million barrels in place is a 60 million barrel give or take, primary recovery resource that sits in front of us.

Of that 60 million barrels, we produced working interest at Lone Pine approximately 10 million barrels. Following my mental math that leaves about 50 million. I see on our books and Shona can substantiate this, we have approximately 35 million barrels booked of the primary 50 million that’s left to go. So again starting from the top, this is a true resource play that is clearly in its early stages. This is not an old depleted asset. Waterflood, secondary recovery will represent an approximately 8% to 10% recovery factor on top of primary.

Again, so I can do the mental math on that, 10% of 600 million barrels is another 60 million barrels of waterflood reserves working interest net to Lone Pine on top of the primary. But probably more importantly is the commercial or economic implications of that. Pinecrest, Lone Pine and other operators in the area have done a great job of delineating and finding ways to extract oil on a primarily recovery basis. And I’ll suggest that the drilling and completion methods between the different operators out there are converging, I’ll use the word converging.

Lone Pine continues to look at longer laterals. We look to tailor-make our frac programs according to not just our experience on the Slave Point but everyone’s experience on the Slave Point, with the ultimate economic goal here to drive capital efficiencies down. Capital efficiencies for primary recovery are tougher. We have a ballpark $3 million primary well that generates a 30-day IP of roughly 145 barrels a day as per Shona’s number. That math would suggest a capital efficiency of approximately 21,000 – 22,000 if you want to throw in some more infrastructure per flowing barrel per day, average metrics.

The boe of the waterflood clearly starts to shine after that, because again operators have invested in infrastructure, land, roads, pipelines and batteries as much of that sunk capital shows up in much improved economic returns in subsequent waterflood recovery. When we infill drill and test our horizontal injection patterns, it is with the ultimate goal to drive those capital efficiencies from the 21,000 to 22,000 of flowing barrel down to I don’t know the end number, yet nobody yet knows the end number but it’s a number substantially better than that in terms of capital efficiencies.

And again the point being there is as much water flood or secondary recovery oil in the pool, as there was primary. So sorry for the longwinded answer, I wanted to frame the discussion because we are believers in the long-term waterflood potential and see a significant economic impact of it.

David Schumann – Northwest Capital

I appreciate the detail very much. If I can just follow on a question asked by the previous person on the line, you’ve referenced the $10 million dollars that you spent last year, in reading through the 10-K, it looks like you acquired a 100,000 net acres in 2012. Is what you’re implying that this acreage is fairly concentrated and if you’re able to discuss your plans for developing the concentrated acreage or just comparing it geologically to the opportunity at Evi, is it somewhat comparable in size? Thank you very much.

David Fitzpatrick

Yes, thank you. It’s Dave here still. Yes, it is a concentrated land package and it’s an asset package that does have access to it, although remote, there is access to it. And you are absolutely correct sir in terms of the size, 100,000 net acres in fact by my calculation would be slightly larger than the asset base size that we have at Evi.

David Schumann – Northwest Capital

Thank you. Good luck.

David Fitzpatrick

Thank you sir.

Operator

Thank you. The next question comes from the line of Roger Serin of TD Securities. Please proceed.

Roger Serin – TD Securities

Sorry, just a couple of follow-up questions. Can you give us any updates on what I am going to call some of the litigation issues, whether it’d be related to the IPO or your ongoing discussions with the Quebec government?

Shane Abel

So on the Class Action lawsuit, Roger, there is no new statement from Lone Pine other than what’s been filed publicly in terms of the Quebec NAFTA litigation or statement of claim, again there is no update there. We’re proceeding down the available path on remedy. And all of that is detailed in – more detailed in our 10-K, so I would encourage you to look at that filing from yesterday and see that disclosure in there.

Roger Serin – TD Securities

Okay, two other questions, Dave touched on and so maybe Dave would want to follow-up on this. When we look at long wells or Shona, when we look at long wells in the Slave Point versus shorter lateral wells, we actually see the longer wells or at least some of the competitive wells is doing noticeably better from at least on a potential EUR basis, is that one of the drivers that’s causing you to rethink your strategy from a completion in drilling point in view and where are you in that process?

Shona Mackenzie

Yes, I mean I think it’s a combination of things, I mean obviously we see the same information said that you see, we’ve had some long wells drilled on our land base by our partner. And so it’s the combination of the company [ph] but I think the key thing really is that the capital is finally starting to work on the longer wells and so you’re really starting to see the capital efficiencies that Dave had mentioned earlier look a lot more attractive. So that’s certainly something that we are considering going forward.

Roger Serin – TD Securities

Okay. And last question I ask, can you maybe Shona, provide any details on your – what I think is your Montney well that was drilled in sort of a kash [ph] area or Blueberry area?

Shona Mackenzie

Yes, you are correct. We drilled a kash [ph] well – a well at kash [ph], and we have not completed that well at present and we’re still evaluating and making the decision as to what we’re going to do with it.

Roger Serin – TD Securities

Okay, thank you very much.

Shona Mackenzie

But we are encouraged by what we saw.

Roger Serin – TD Securities

Thanks.

Operator

Thank you. There are no more questions in the queue at this time. (Operator Instructions) And we have a question from Jeremy McCrea of AltaCorp Capital. Please proceed.

Jeremy McCrea – AltaCorp Capital

Hi guys, just a comment on your infill wells, are you seeing any reservoir pressure declines and how many opportunities I guess do you see for waterflood potential here and how quickly – and then how material could it water for the say 2014?

Shona Mackenzie

So I’ll address the first one on infill wells. So we drilled our 10 wells per section pilot in September last year and brought those wells on-stream in October. We did drilling and completion operations, we didn’t see anything that would indicate reservoir depletion and now we brought those wells on-stream. They perform as expected as per type curve expectations and we do not see any signs of interference with the other wells. So everything would indicate that we have tapped into primary – more primary productions of our reservoir.

The second question with regards waterflood and the longer term potential, I mean obviously we’ve had a vertical waterflood pilot underway now for a year and a half. We’re looking to do a horizontal pilot later this year and typically we would want to run those pilots for at least a year before we would make decisions about rolling out on a field level. But what we do see and David talked about this is secondary recovery potential here is huge and to maximize that obviously we’re looking at implementation at a field level, not just in portions of the field.

So going into 2014, I would expect we would have starting to see horizontal pilot results and then starting to work up what the larger plan looks like.

Jeremy McCrea – AltaCorp Capital

Okay. And maybe actually just one more further question, what’s your – this is just more of a holistic question I guess, but is the option still to dissolve the whole company or do we want to build up the company a bit more here before looking – to sell the whole company ideally?

David Fitzpatrick

Jeremy thanks very much. It’s Dave here. From my experience might suggest that, number one, we’re a public company. There is the answer to your question, the direct answer. And then my experience would suggest that you don’t – the only way you ultimately sell a company is not with the designation or the desire to sell it. You become – in the public market, this is not a Lone Pine comment, this is just a market comment, you would potentially become a public company, a desirable entity if you are a live going concerned healthy entity. And that is our goal.

Jeremy McCrea – AltaCorp Capital

Right. Okay, sounds good. Thank you.

David Fitzpatrick

Thanks Jeremy.

Operator

Thank you. (Operator Instructions) We have no more questions. I’d now like to turn the call over to Shane Abel for the closing remarks.

Shane Abel

Thanks Mathew, and thanks to everyone on the line that has joined us this morning. We hope that we’ve given you an adequate update of what’s going on at Lone Pine and look forward to further updating you on some very exciting initiatives very shortly. Thank you.

Operator

Thank you, Shane. Thank you, ladies and gentlemen for joining today’s conference. This concludes the presentation. You may now disconnect. Have a good day.

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