Peyto Exploration & Development Corp.

Great. Well, thank you.

Welcome everyone to Peyto's fourth quarter and year-end 2014 results conference call. And despite what the commodity prices are doing outside, we are here to talk first and foremost about 2014 before we get on to some more forward-looking, and for us 2014 was an outstanding year.

So I first want to throw a big shout out to the Peyto team for such a great job that they did last year and despite where oil prices are, you are going to have to excuse us, but we are going to be pretty upbeat today because we are talking about a pretty spectacular year that we just had. In the room with me today, we have got the whole Peyto management team, now expanded.

So that consists of Scott Robinson, our Chief Operating Officer; Kathy Turgeon, our CFO; Dave Thomas, our VP Exploration; JP Lachance, our VP Exploitation; Tim Louie, our VP of Land; and our two newest members, Lee Curran, our VP of Drilling and Completions; and Todd Burdick, our VP of Production. And then of course we have also got, Jim Grant, our Investor Awareness rep.

Jim, I see you have got a big list of questions so why don’t you take it from here.

Okay. For those of you who are new to our conference calls, we hold the first half as a question-and-answer session where I ask some of the senior management questions about Peyto and its latest financials before we turn the call over to questions from investors and representatives of investment businesses.

Darren, I count a record number of new records being set on the first page of our 2014 year-end news release. This looks like growth in all aspects of our business.

What message about our growth do you want to share with our investors?

You know, Jim, we talk a lot about our growth but I think the bigger message that we need to reinforce is that the growth is a byproduct of us having very profitable investments in 2014. That’s the ultimate goal around here.

We are not just interested in being a bigger company. I think everybody in this room would agree that they don’t want to just manage more people and manage a bigger asset base, we are looking for maximum amounts of profit.

And we can generate that in one of two ways really. We can either deploy more capital for the same returns which is how we did it really in 2014, we had our largest capital program ever of $690 million and we achieved very similar returns on that capital.

26% to what we got in 2013 which is around 27%. Or I suppose we could deploy less capital and get even better returns to generate the same amount of profit.

And really that’s something that we are looking at for 2015 using probably even lower capital spending but at the end of the day getting more work done, more activity done and even better returns on it because the cost that we are going to see in 2015 are going to be less. So regardless of the growth, the growth ends up being the byproduct of us doing a very good job investing capital.

It's the profitability that I want to highlight first and foremost for shareholders. I think that’s the biggest accomplishment in 2014.

Okay. turning to Todd Burdick, our VP of Production, one of the two newest members of our management team but a member of the Peyto team since 2004.

Todd, can you provide us with a summary of the areas and facilities that contributed to our production growth from 75,000 barrels of oil a day equivalent in 2014 to over 85,000 at the end of the year.

Yes. Thanks, Jim.

2014 was our busiest year in terms of facility processing and compressor additions. In the Greater Sundance area we added seven compressors and one 50 million a day refrigeration train.

And in Brazeau we added two compressors and one 30 million cubic feet a day refrigeration train. Net to Peyto, that positioned us to have about 5000 to 10,000 Boe of growth room coming into 2015.

We added 41,500 Boe a day of new production over the year. All of this growth occurred in Greater Sundance about 38,000 Boe a day, with the remainder about 3,500 Boe a day in the Brazeau area.

Combined with the base production, we exited the year at 85,700 Boe a day.

Todd, can you also update us on production for 2015 including the impact of such things as TransCanada's transmission pipeline outages and the impact of low liquids prices.

Yes. Jim, our production for the first couple of months of 2015 has been impacted by two issues that are outside of our control.

TCPL, the province's main gas carrier have had ongoing capacity restrictions which have caused producers north of Rocky Mountain House to curtail production below their previous norms. In our case, we have experienced and will continue to experience for the balance of the quarter, reductions in our volumes because of that situation.

To date these curtailments have reduced our production by approximately 775 Boe a day. The curtailment related to compressor maintenance and line integrity investigations.

There are periodic interruptions on the horizon through the summer month but we don't expect the same impact as system volumes decline as draws from Alberta storage come off the system. The liquid pricing situation has also affected us for these first two months of production in 2015.

As a result of tremendous supply growth we saw the base price for propane plunge from $89 a barrel Canadian FOB Edmonton for January of 2014 to $7.42 a barrel for January 2015. When we consider the deduction for transportation and fractionation which ranges from $3 to $10 across our properties, the recovery of liquid propane has become largely uneconomic.

We have been seeing improvements in late February and March as supply [corrects] [ph] but we made the decision to reduce propane recoveries at our plants from normal level to 26% to a recent level of 19% overall. But leaving some of the propane in the gas stream we have maximized the profit for this small part of our production stream but there has been an impact to our production of 550 Boe a day based on 6:1 energy equivalency factor calculation.

Now while there have been these inverse impacts to our realized production total of about 1300 Boe a day, it's important to note that none of this relates to the resources we are producing. On the contrary, our 2014 wells have been performing very well and we have added some additional very strong producers through our Q1 activity today.

And as the TCPL problems resolve NGL prices come back to where they should be, it will reflect in our production numbers.

Okay. Thanks, Todd.

My next question is for Lee Curran, the second new member of our management team as our Vice President of Drilling and Completions. Lee also brings substantial experience from his many years on the Peyto team.

Lee, can you speak to the record level of drilling and completion activity we saw in 2014. What milestones would you highlight and key accomplishments can you reflect on that will take us forward into 2015 and beyond.

Sure. Jim.

In 2014, Peyto spudded a gross well count of 123 wells utilizing a fleet of nine drilling rigs. Although we have seen short periods of similar activity levels in prior years, during 2014 we were able to maintain continuous operations with that fleet including an active drilling program through the traditional breakup period on seven of these nine rigs.

Now a typical operator in the Deep Basin may achieve 225 to 250 operating days per rig in a given year, however much of our fleet realized in excess of 320 operating days per rig. As a result we were able to conduct an 11 to 12 equivalent rig program with only nine rigs.

Now this means of accomplishing more with less resources linked to greater efficiencies. In the Greater Sundance are we continued to realize gains not only in our averages but also on our pace setter operations.

In 2014 we realized our fastest drill times of 14 days from spud to rig release in both our horizontal well rigs and [flare] [ph] categories. Our notable performance gains perhaps have been realized in our expansion areas of Brazeau.

We have drilled a total of 21 wells to data there, and early in the development of that area borewell instability associated with the [indiscernible] coals presented us with significant challenges. However, late 2014 and early into 2015, we have overcome those with significant performance improvements.

To provide some color on this. Through 2013 our initial five wells drilled averaged 35 days at a cost of $3.9 million.

Our most recent five wells through late 2014 and early 2015 have averaged less than 23 days at approximately $2.8 million drilling case. Furthermore, the most recent two of these wells were drilled and cased at a cost of less than $2.4 million each.

We are very encouraged that we have begun to realize Sundance type performance cost structure in this area and that would further strengthen our economic returns. We frequently measure our operational execution, both internally and externally and we continually find our nearest competitor to be our self in the prior year.

Looking through the remainder of 2015 and beyond, we will continue to strive for performance advancements that will maintain our position as the supply cost leader in the Deep Basin.

Thank you, Lee. Scott, turning to our Chief Operations Officer and VP of Operations, Scott Robinson.

With record activity levels in every aspect of our operations in 2014, how are we managing to keep the capital and operating efficiencies we see in our 2014 year-end results as we grow at such a rapid pace.

That's a good question, Jim. I think a lot of people ask that question.

We amaze ourselves year-over-year, but I think it's really all about our focus and the workplace culture that we have here at Peyto. We enjoy most of the same organizational attributes that we had ten years ago.

Yes, we have expanded the team slightly to handle these increased volume of work that this expansion has brought about. But we have maintained the organization as a very flat organization.

Each team member has a lot of authority and responsibility. There is very little overlap in work activities and the communication levels amongst our individuals are strong but it's not burdensome.

The greatest portion I think of every team member's day is spent doing productive work. I think sometimes it's not always what you do but sometimes it's what you purposely don’t do and we try to keep our business simple and ensure that the work that we are doing is working towards positive outcomes.

And then we try to minimize any kind of time wasting activity. So we have maintained that culture through the years and it's allowed us to achieve what we are doing.

When you combine that discipline with the discipline as a group to hold through our strategies and stick to the geographical areas that our resources fall in and where our expertise lies. And we layer on top of that the team's continual quest to, as Lee mentioned, to improve our execution.

We are rewarded with these consistent outcomes year-over-year. This approach has put us at the front of the pack certainly in the Deep Basin and in the industry in general in terms of total cost performance.

And that’s not a position that we are out to give up.

Thanks, Scott. Turning to our VP of Land, Tim Louie.

Can you give us a summary of our land acquisitions in 2014 and a general indication of where those new lands are located.

Thanks, Jim last year we acquired 38 sections Crown land sales. We also did a minor asset acquisition involving an additional six sections.

So in total we spent $12.9 million for less than 2% of our capital budget to buy our 44 sections. With respect to where these new lands are located, about 60% of these new additions are situated within our Greater Sundance and Brazeau areas.

The rest of our 2014 acquisitions are positioned between these two areas. And it is worth mentioning that we will continue to focus our acquisition efforts on lands and continue to stock [cretaceous] [ph] targets that we routinely exploit.

Okay. Thanks, Tim.

Turning to our CFO and VP of Finance, Kathy Turgeon. Kathy, one aspect of our business that is a little different from most of our peers of our size who grow by acquisition, are our tax pools.

Can you describe where they are at the end of 2014 and how do we manage to continue to generate these pools?

Well, as outlined in our MD&A, our tax pools at the end of 2014 totaled $1.5 billion which are comprised of $800 million of CDE, $385 million of CCA, $232 million of COGP and $86 million of CEE and the balance consists of share issue costs and cumulative eligible capital. As wells are drilled and completed, we generate CDE and CEE pools.

Facilities, pipelines, well equipment etcetera, generate CCA pools. Property acquisitions generated COGP and CCA of tangible assets required.

The majority of our pools DE and CCA give us a tax rate operate of 25% to 30% per year. If we grew primarily by acquisition of property, we would have mostly COGP pools which are limited to 10% to write off per year.

As you can see, an organic growth strategy is better from a tax perspective. Corporate acquisition can preserve the nature of tax pools.

However, acquired pools are successored and therefore the tax claim can be limited. In addition, pools acquired through corporate acquisitions come with a risk of CRA audit and reassessment.

Thanks, Kathy. Turning to JP Lachance our VP of Exploitation.

JP, in the 2014 year-end news release we mentioned that our 2014 capital program is forecast to deliver a before tax internal rate of return of 26%. How do we come up with that prediction and what is the breakdown by well species.

Jim, as an industry we often talk about capital efficiencies like finding and developing costs or dollars spent at a flowing Boe but that alone does not necessarily mean that wells we are drilling are profitable. At Peyto, we like to look at the prior year's drilling program and calculate the rate of return, as Darren alluded in his opener there, using actual capital spend compared to the cash flow those wells have generated to date and their forecasted cash flows from the reserves assigned.

Now we don’t just include the drill, complete and tying cost per well but also the non-associated well capital like land, seismic and facilities we constructed during the year. We also include the cost of any side tracks or operational problems that we in a while experience.

So naturally when we look at well by well results we get a wide variety of outcomes, but as a whole we have calculated a 26% before tax internal rate of return for the wells added last year based on insights, reserve assignments and forecasted prices. And if we look at the break down of that, the predicted returns on our Wilrich program as a whole yield about 23% return while the Falhers fall between 25% to 27%, the Notikewin proven at 31% and the Bluesky at 21%.

We have continued improvements in our cost structure. We expect to see similar or better returns for our 2015 program even in this low price environment.

Thank you, JP. Turning to Dave Thomas, our VP of Exploration.

Over the last year we grew reserves and included in that growth was a corresponding growth of our drilling inventory. Beyond what is recognized by our independent reserves report produced by InSite Petroleum Consultants, we have a much larger internal inventory of drilling prospects that also grew substantially over the last year.

Could you characterize both the inventories for us and comment on the geographic and geological inventory distribution.

Yes, Jim. Every year our independent reserves report lists a number of undrilled locations which reserves are booked to.

These undrilled locations are in the proven undeveloped and probable additional category. In most cases this booked inventory consists of typically either in field drilling locations or one mile [step out] [ph] locations.

In addition to these independently identified locations, between or maybe side existing productive well, Peyto also has a larger inventory of internally indentified drilling locations that are based on geological or seismic mapping. Now at the end of 2014, even though Peyto had drilled 123 gross horizontal wells during the year, the number of remaining booked horizontal locations had still risen 19% to 747 from 628.

Of these 747 booked horizontal locations, 550 of them are in the key Notikewin, Falher, Wilrich and Bluesky zone which have been the foundation of our growth over these past few years. And in addition to this booked inventory, the number of Peyto internally identified horizontal drilling locations also increased from 1163 to 1237.

Of these locations, 603 are in the key Notikewin, Falher, Wilrich and Bluesky zones. So at the end of 2014, the booked and internally indentified inventories combined to yield a total of 1984 horizontal locations of which 1153 horizontal locations are in those key Notikewin, Falher, Wilrich and Bluesky zone.

That’s a pretty healthy inventory in relation to Peyto's level of drilling activity. Geographically, the new additions were pretty evenly distributed in the Greater Sundance, Ansell and Brazeau areas.

So really Jim the important point here is that although Peyto has had a very active drilling program in 2014, we continue to add new drilling locations at a faster pace than they were drilled.

Thank you, Dave. Scott, in some previous years we worked more aggressively through the breakup period in others less so.

Can you speak to how you see this year's activity through the traditional breakup period.

Yes, Jim. As Lee has pointed out quite astutely in the past the opportunity to keep our operations going even during some of the tough access periods during breakup really provides a benefit to our business in terms of overall efficiency and results and caused the performance.

It's best to keep going while you have got the momentum rather than to stop and endure the difficulties of restarting after breakup. So we have learned from that.

It also provides for a smoother operations in terms of wells feeding into our facilities. So through this experience over the past couple of years, we have made the decision to undertake a reasonable level of sensible drilling activity during breakup as costs allow.

Lee and his group are very busy right now and have been busy preparing for this upcoming breakup and I will let him tell you a little bit more about that.

Thanks, Scott. As previously mentioned, we were fortunate last year to conduct continuous operations on 7 drilling rigs and 4 active completion spreads throughout the breakup interval.

We are presently hosting discussions with road owners in our areas and taking steps towards spring breakup program that’s here, should we experience similar favorable conditions as those we saw in 2014. Now should conditions deteriorate such that continued operations through breakup become unrealistic, we will be well positioned with project inventories and applicable resources to aggressively execute these projects in the second half of the year.

Lee, our largest expenditures are the capital to drill and complete our wells. Right now, with the drilling activity in Canada at an all time low, what has happened to the pricing we are getting from our suppliers of drilling and completion services and materials?

Sure, Jim. You know that’s a hot topical right now.

Peyto's contracting strategies have long proven successful and this is really just an extension of what we have always done. We endeavor to employ contractors that take pride in providing quality products and services.

We have historically been able to offer very high utilization relative to our peers and for that we have yielded preferential pricing arrangements even through busier market conditions than what the industry is experiencing today. Our suite of suppliers has and continues to be responsive to the current environment.

Our largest single elements in well construction are pumping services, drilling rigs and tubular goods. Now we have seen significant reductions in the first two categories and pending reductions in the third category as we deplete our committed inventories.

To date we have realized approximately 10% drilling and completion cost reductions solely on the basis of service cost reduction. As mentioned, a large component of this has been borne by reductions in pumping services and drilling rig day rates.

However, we continue to have regular and candid rate discussions with all of our service providers. Should these low activity levels persist, our suppliers will undoubtedly be successfully in negotiating improved labor and supply costs from their respective vendors and further allowing discounts to be passed along to us.

Thank you, Lee. JP, beyond the pricing reductions that Lee just mentioned, what technical changes to our completion design are we contemplating that will have an impact on our well cost as we continue to drill in this low price environment.

Jim, some of the completion design aspects we are already experimenting with include, the amount of energizing fluid we are using on our fracs, sand types and quantities, the amount of chemical additives we use for fracs and recycling of flow back water. There is nothing new here and we had looked at these things in the past before but when the price environment is such that it is, everything is on the table.

So of course we need to evaluate both the short and long-term effects of well performance with these trials but early results are encouraging showing no negative impacts on performance and could lead to sustained completion cost savings of about $100,000 to $200,000 per well beyond those reductions that Lee mentioned. All this is to ensure we continue to add value with the wells we drill and keep those returns at levels we have grown accustomed to, again at this low price environment.

Thank you, JP. Darren, you wrote in the 2014 year-end results news release that Peyto was eager to take advantage of the current environment of uncertainty in effect being greedy when others are fearful.

Can you elaborate both on how you view the current uncertainty in the energy market and how we will be able to take advantage of it?

Sure, Jim. You know we have said it before and we will say it again, that Peyto tries to be very counter-cyclical in our business approach and quoting Warren Buffett, we want to be greedy when others are fearful and I think very much so we want to be fearful when others are greedy.

It applies particularly well to the oil and gas industry because tends to be a cyclical commodity business and there is a lot of boom and bust in the industry and if we can get off cycle with it, I think we can do very well. As these guys have talked about, there is some benefits obviously to continuous operations.

We are seeing a lot of other operators cutting capital programs, as a result costs are falling. That’s when we want to be particularly active.

We want to take advantage of those low costs because we know that that has a positive effect on our returns. If you look at a simple cash flow analysis and a simple returns analysis, capital is at the front end, it's undiscounted.

And so if you can get a reduction in the capital, that’s a direct improvement in your return. And usually that comes becomes we have got short-term softness in commodity prices but that's typically isn't going to be soft like that over the life of the asset but the capital has crystallized once you spent and it's at the start, at the very front end.

So if we can be busy either with deployment of capital in drilling wells and completing wells in time, buying facilities or even buying land. As Tim mentioned, last year's land purchases were I think over twice what we spent in 2012, for instance, when gas prices were soft.

So there again we are looking at another year where if commodity prices are soft, activity levels are down, probably will be very little competition for land and the prices will be way down. That’s a perfect time for us to pick up drilling inventory too.

So we want to be greedy right now. That’s, I know that maybe it sounds bad but from a shareholder perspective that’s when we can maximize the returns, generate the best returns.

We want to put as much capital to work in this environment as we possibly can.

Okay. Thank you, Darren.

Mary, I would like to turn the call over now to questions from investors and representatives of investment businesses.

I had a quick question about your previously announced 2015 outlook. You guys have formally announced a capital budget in between $700 million to $750 million.

However, when I look at your [predo] [ph] on the Web site, you make reference to approximately potential savings of upwards of 20% and then $600 million budget for 2015. Is this a targeted budget range and when would you look to formally discuss a revised budget?

Thanks.

Yes, Rachel, it's tough this year because it's very much a bit of a moving target, right. The activity that we have planned out in the fall and that we laid out, we are going to attempt to do.

Assuming, obviously, weather cooperates and we can drill through breakup as we did last year. We are going to try and accomplish what we originally set out to do this year.

And that is an aggressive, more wells than we drilled even in 2014. The challenge of course though is that because the costs are changing so dramatically, [indiscernible] in the cost.

Last year when we set that budget in motion, we had 2014 costs and we had good historical idea of what wells are going to cost and what that capital program was going to ultimately cost us. Then service costs started changing dramatically.

And so we expect over the year that we can achieve that same amount of activity for, hopefully 20% less than that $700 million to $750 million range. Now as Lee talked about, we have got 10% already in pocket, we should see some more savings hopefully even as we drill in the breakup.

And beyond breakup, the activity levels are very uncertain right now. There could be even less activities than it's currently projected.

Rigs could stay shut down, competition for services gets even greater and we could see even additional savings. Now the one other piece that we do have, I guess, changed from that original budget is that we don’t have to be as aggressive ordering out new facilities with as much lead time.

That jobs are not quite as busy anymore, we don’t have to get gear on the road nine months in advance anymore so we can actually delay ordering some of the equipment that we foresee needing into the future, probably outside of 2015. So we get a onetime really reduction in facility cost, probably for this year as we tighten up that timeline a little bit.

So as I talked about, it's a little bit of a tough thing to pin down exactly what well costs are going to be when they are changing so dramatically. I think as we get into breakup we would start to see beyond breakup and the levels of activity for the summer, we should be able to come up with a more firm revision to what the capital program is going to ultimately cost us.

And I am hopeful and I think we are all quite optimistic that we can get up to that 20% savings number.

You mentioned in the prepared remarks that you had seen some strong well results in the 2015 year-to-date. Can you just give some more color, what areas, what targets and then a detail on those results?

Sure, Kevin, thanks for the question. I got to pass it off to JP who probably knows some of those individual wells by heart.

Yes, we don’t typically get into specific wells on its early days but what we are seeing on average from our 2015 program is we are slightly ahead of the curve, our average for 2014 with the group of wells. I mean as far as the specifics go, we had some good results in wells down in our area we call [Pedly] [ph].

We had some other good results right in the heart of Sundance and in some other areas in Ansell. So really all across the board there, without getting into too many specifics, Kevin.

Okay. And then you said that you are testing some new completion designs, just tweaking some things that will result in just tweaking some things that would result in additional cost savings.

What are you doing differently?

We are just -- we have experimented because we have some data in the past about sand types that we are using. Just different types of sand and changing up a bit of the recipe.

We haven't fundamentally changed our design as far as what we do. But these small changes have an impact and it's all about getting those costs and so far so good.

So far we are seeing not a detrimental effect in the short term, we don’t know if that will affect us in the long term and that’s important to understand. So at this point it's mainly the sand, some nitrogen.

We have talked about energizing fluids that we have backed off a little bit in some areas. But this is not a recipe we can apply to every formation in all areas so we are being selective in that regard.

Okay. Great.

Then last one, how was the steep decline in liquids prices in the last five or six months here? How has that shifted your focus in terms of the targets that you're going to go after?

Are you moving more to deeper gas zones?

I think, Kevin, we already had -- when we had looked at a comparative analysis between the more liquids rich formations prior and the drier gas formations. Gas prices got really soft, down into that $2 range and we still had $100 liquids prices.

Clearly formations that have more liquids productions were the ones that were offering better returns. But when gas gets back up to about $3, even at $100 liquids prices the drier gas formations because they are more productive and sometimes actually tend to be cheaper to go get even though they are deeper, they have offering us a better returns.

Now you have got liquids prices much lower and as Todd pointed out, propane prices that are pretty much zero in terms of what we are getting here in the first month of the year. So we had to obviously warm up the plants and reject propane.

But I think the deeper dry gas formations now are still wining the day and in terms of capital allocation, as Dave talked about, the bulk of our inventory as we look forward into the future both booked and unbooked is form those deeper drier formations. So kind of funny because the industry had moved quite aggressively into very liquids rich gas production because they didn’t have a cost structure that worked with dry gas and at the same time here we are at Peyto moving in the opposite direction into drier gas formations because we have got an advantaged cost structure that makes those try gas formations profitable.

And then we lose the liquids prices and those were soft, so clearly the guys that have moved all of their resource into the liquids-rich formations are struggling and we are sitting just fine with dry gas again.

Hi, Darren. I just had a question.

I understand your strategy on wanting to drill when costs are declining in this type of slow environment, but given the high decline rates associated with horizontal drilling is there a point where you would say, okay, even the costs are lower I'm just better off waiting because of the high decline rates?

Well, I think ideally, Fai, we would want to deploy the capital when the capital is cheapest and produce the gas when the prices are high up. The challenge of course is trying to predict both of those.

So you can really I think get yourself in a pickle if you spend the capital today thinking this is the cheapest and then you are waiting and waiting to bring on production for the commodity price to recover. What if it doesn’t?

So I think probably the best way to approach it is, run your economics, is if the price doesn’t recover. And are you still deploying capital in a profitable way.

And so we tend to do that as well. We of course run economics on the strip but at the same time we do a double check to see if you held commodity prices flat at this low level, are we still seeing reasonable returns on the capital that we are deploying.

So we know though that when industry pulls back like this, when activity drops way off, that there tends to be a production response ultimately and that tends to drive a price response. So you just know because of the cyclicality of the commodity that when we are in low like we are, when there is no activity happening, when the cost of services is really low and this is when we want to deploy capital, that you are likely to see a commodity price response down the road.

How long that takes, we don’t know, we can't predict into the future but we protect ourselves obviously with active hedging program that moves out some of that volatility and also with the cost being so incredibly low that we are still making profitable investment decision even if commodity prices stay where they are.

Great. Well, thank you very much.

As I said, we had a fantastic year last year and that was due to a lot of hard work by this Peyto team. As Scott mentioned, it's a small team with a bit of a unique culture for sure.

I think it was the one part of our business that didn’t grow very much. In fact, I think we added one person last year and grew from 47 to 48 people at Peyto.

But we are still very consolidated on one floor just like our asset base is consolidated in the Deep Basin. And we are looking for another exciting year in 2015.

A little bumpy to start off, of course as Todd mentioned, but I think the year is going to prove to be one of the great ones when we look back on it. 2012, when we look back, was a year of very soft gas prices and we did some spectacular stuff that year too, including making our only acquisition.

So who knows what holds ultimately for 2015 but we have got some big plans with the drill bit to start off with and then we will see what comes. But stay tuned as we progress through the year, we will be back to you with Q1 release in May.

Thanks for listening.