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Forest Oil Corporation (NYSE:FST)

Q4 2009 Earnings Call Transcript

February 23, 2010 2:00 pm ET


Patrick Redmond – VP, Corporate Planning and IR

Mike Kennedy – EVP and CFO

Craig Clark – President and CEO

J.C. Ridens – EVP and COO


Dave Kistler – Simmons & Company

Scott Hanold – RBC Capitals Markets

Brian Singer – Goldman Sachs


Good afternoon. My name is Regina, and I’ll be your conference operator today. At this time I’d like to welcome everyone to the Forest Oil Corp. fourth quarter and yearend earnings 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) Thank you.

I’d now like to turn the call over to Patrick Redmond, Vice President of Corporate Planning and Investor Relations. Mr. Redmond, you may begin the conference.

Patrick Redmond

Thank you and good afternoon. I want to thank you for participating in our fourth quarter and yearend 2009 earnings conference call. I will also note that the replay of this conference call will be available through March 9th as described in our press release issued yesterday. We have joining us today, Craig Clark, President and CEO; Mike Kennedy, Executive Vice President and CFO; and J.C. Ridens, Executive Vice President and COO.

Some of the presenters today will reference certain non-GAAP financial measures regularly used by Forest in measuring its financial performance. Reconciliations of such non-GAAP financial measures with the most comparable financial measures calculated in accordance with GAAP are available on our website and can be viewed by clicking on Investor Relations tab, then non-GAAP at

In addition, I’d like to caution you about our forward-looking statements. All statements other than statements of historical facts that address activities and outcomes that Forest expects, assumes, plans, believes, budgets, forecasts, projects, estimates, anticipates, et cetera, about what will, should or may occur in the future are forward-looking statements. Please carefully review our cautionary language regarding forward-looking statements that is contained at the end of our press release.

Before we get started I’d like to remind all of you that Forest is hosting an Analyst Conference the afternoon of March 18th at New York. Senior management will discuss further details associated with Forest’s core assets and its 2010 business plan. If you would like to attend, please send an email to

I will now turn the call over to Mike Kennedy. Thank you.

Mike Kennedy

Thanks Pat. Thanks everyone joining us on a busy earnings day. The fourth quarter results were generally inline with expectations while our divesture program exceeded expectations. Productions came in at the midpoint of guidance with differentials in lease operating expense improving once again. This led to better than expected adjusted EBITDA and adjusted discretionary cash flow.

The quarter, however, is dominated by divestiture of our non-core Permian and Canadian properties for proceeds in excess of $900 million and the corresponding reduction in net debt. Production in the quarter was $459 million a day, down 4% compared to Q3. However, production pro forma for the divestitures was flat compared to Q3 2009.

Unhedged gas realizations were $3.81 per Mcfe. Gas differentials continue to narrow the $0.35 per Mcfe for the quarter compared to $0.51 last quarter. Differentials tightened across the entire portfolio most dramatically in the Texas Pan Handle and East Texas, Northern Louisiana.

Lease operating expense for the quarter decreased once again $1.10 per Mcfe, down 6% from last quarter and a remarkable 13% from last year. Our focus on this line item continues to drive margin enhancement.

Cash, G&A expense for the quarter increased to $0.42 per Mcfe due to severance associated with the divestitures and a true-up of the bonus accrual. However, for the year, G&A expense decreased to $0.29 per Mcfe continuing poor standing and a lower quartile of the industry. Cash, taxes during the quarter were $69 million as the divestitures resulted in a tax gain. Forest is able to shelter majority of this gain by utilizing its legacy NOL position, but still had to pay $69 million, which is a good indicator of the substantial value realized from these divestitures.

Now on to liquidity. During the quarter, Forest reduced its net debt by $915 million through asset sales and free cash flow generation. Asset sales generated over $900 million in the quarter and free cash flow for the quarter is $14 million, as discretionary cash flow of $172 million exceeded capital expenditures of $158 million, despite spending $44 million of capital on leasehold acquisitions.

These two items allowed Forest to repay all of its borrowings under its credit facilities and have cash of $467 million on the balance sheet at December 31st, 2009. The resulting liquidity of greater than $1.7 billion is an all-time high for Forest and we still have a handful of non-core properties to sell.

In summary, the fourth quarter marked a significant turnaround for Forest. We are able to delever the balance sheet to more normal levels, increase our hedge position and ramp up rig activity. The increased rig activity stabilized our production base and our relentless cost focus maintained our margins. This in turn sets up 2010 nicely where we planned our organic growth from Q4 to Q4 at a double-digit rate, while capital expenditures are expected to approximate cash flow.

With that, I’ll turn it over Craig.

Craig Clark

Thanks Mike, good job on your remarks. Mike and the finance team had the ground running which shows one of the strengths of the company in terms of its talent and deep bench. I am always asked about the quality of our assets and mention that we have an excellent portfolio that allows capital re-allocation and flexibility for future success. Well, we also have a portfolio of individuals to promote from within that provides for the same future success.

Our fourth quarter 2009 accomplishments particularly in December alone are a testament to how quick this organization can move on transactions while ramping up activity at the same time. Despite the roller-coaster ride in commodity prices, again in 2009 our company fared well in the following. Organic reserve replacement and low funding costs, some of the best in the peer group.

CapEx spending discipline in the low commodity price are higher service costs periods. Operating cost per unit reduced yet again and I guess the four straight years. Expanded margins further from liquid NGL processing contracts especially important in place like the Granite Wash. We sold approximately 1.1 billion of non-core assets in a rapid fashion, heavy if it’s on the word rapid had excellent highly accretive metrics. We put the balance sheet in excellent shape as a result of this. We added significant acreage that J.C. will talk about in our main core areas at affordable prices.

Last but not least we achieved proof of concept on our Horizontal Program, specifically the Panhandle Granite Wash and the Bossier/Haynesville. I feel somewhat vindicated personally and our predictions for the Granite Wash are tight sand horizontals in general along with our predictions in Haynesville, East Texas, or Bossier where we said, don’t sell Texas short. J.C. Ridens will follow me with the operations activity and update 2010’s activity prior to the Analyst Conference.

Let's start with the metric everyone focuses on on yearend proven reserves and reserve replacement. Our proven reserve into the year at 2.12 Tcfe using the new SEC 12 month average process of $3.87 for NYMEX gas, and roughly $61 a barrel for crude. I should note a couple of items in regards to our yearend reserves, and we pre-released those several weeks ago.

Over 300 Bcfe of purely 2009 price revisions would all be returned to yearend pricing. The 75 Bcfe mentioned from the new roles are solely from drilling horizontals within the field or fields for vertical development wells already exist between the new horizontals, examples of EB in Canada and Gilmore in East Texas. Not booked yet on the new Granite Wash horizontal offsets.

The small amount of performance revisions of 31 Bcfe are primarily from replacing verticals with a horizontal well in certain areas and using the five-year rule for PUD drilling. In terms of PUD bookings, our PUD percentage remained flat from 2008 to 2009 at 37%, it looks like we are somewhat in the minority on this metric. PD approved developed reserves take on more importance this year. As mentioned with the above categories we remained conservative. Our all sources, finding and development cost even with the price-related revisions average $2.16 per Mcfe. This alone would have compared favorably to the five-year average.

Our organic F&D without price-related revisions might be the lowest we've seen at $0.99 per Mcfe. People want to see organic, well, we have shown the organic with the flat PUD percentage, so there you have it. The cost of our land, seismic and capitalized overhead are, of course, included in these finding cost numbers. What you see from our reserves and associated finding cost efficiencies are growth areas that have repeatable economic and optional growth, most of which that are in front of us.

Our capital spending was right down the line with guided amounts including approximately 150,000 net acres of new undeveloped land in our core areas. We spent $569 million on E&D activity in 2009, approximately 70% of EBITDA. We drilled 117 gross wells with a 94% success rate. Be careful with the well count as we go forward because about two-thirds of our program is now directional or horizontal. We did spend quite a bit of CapEx on the property sold, primarily in the Permian, which helped us to get value.

Also during 2009 we saw service cost decline pretty much across the board, probably greater than the 20% we predicted at the beginning of the year with three exceptions being mud, the frac proppant and fuel. I should note that companies were able to see these reductions like forced, if and only if, they didn't high price term contracts for the rigs and services and were aggressive in negotiating discounts. Low commodity prices or the prices today for the commodities still mandate this aggressive cost behavior.

In term of operating expenses, same old story, same excellent results. We were able to reduce per unit operating cost by 19%, remember that’s per unit in 2009, yet unlike many competitors we have done it for four years in a row, I think. This is from an already low base that we have reduced operating cost by 19%. We believe operating cost controls is an important – it’s finding costs and resource play. History has shown that we cannot count on top line commodity price growth, therefore cost extraction and margin extracting becomes increasingly important in the development of the so-called resource play.

Our net production declined in the fourth quarter mainly due to the divestitures average 17 million a day; we sold more than but most of it came out in December. In fact we closed all the fourth quarter packages early, very early and sorry for all the pro forma numbers. We had the usual winter downtime, records known North Texas yet most activity continue throughout the crummy weather.

Our R&D activity was almost entirely D or divestitures using -- during the fourth quarter and all of 2009. More importantly, our sales came from non-core properties. All of the Canadian packages of around 120 million were non-operated. The last large Permian package was the only major operating package we sold. The overall metrics were approximately 16,000 for flowing MCF per day overall and approximately 13 times EBITDA overall.

Highly accretive to the four shareholders and notably authoring flowing metrics above which we planned to add incremental veg production going forward. Further showing a roughly 12% of the company’s production were approximately 1.1 billion, to give people a comparison for what the company is worth to some other parts.

Since 2007, our gross well count has gone from 10,000 gross wells to currently near 5,000 wells which are predominantly now operated by us as opposed to others before. This is been a huge upgrade in our asset portfolio, calendar estimate it. I should compliment our business development, finance, western business unit, legal teams, Canadian business unit who were involved in all the transactions in 2009. The largest transaction the Permian shale to SandRidge, I think 9 days from data room opened to signing an agreement and are only 35 days from data room opened including weekends and the thanksgiving holiday for those of us that didn’t get it off. So good job here. We’ve also signed agreement to settle another 13 million roughly of remaining non-core – Canadian non-core properties which is expected to close in the first quarter of 2010.

Before I turn the call over to J.C., I should comment on the macro environment. All those stores came rolling down to the five-year average to past two months on the gas side. Oil field spending has remained up industry wide throughout 2009, surprises, in fact, and will apparently increase based on gathered amounts from us and competitors. The rig count has become increasingly irrelevant for the industry due to the influx of horizontal activity, forest included. The industry CapEx spin rate would tell you the gas supply will hang in there, however, it’s the spin rate not the overall efficiencies amended drive the production hands. The decline for the industry per take by the Shale is as real as the offshore decline curve been resumed in 2010 since we had a good year for hurricanes last year.

Even though we remained bullish on gas long term, we run our economics at $5 NYMEX and $60 crude. The basis differentials have been restored to normalcy. Recently they were running to gas at $5. That we remind you before J.C. goes into the 2010 plant spending, that a number many of our vertical multi-play wells are economic of $5 gas. However, our choice to do horizontals or deviated wells and tight gas sands and shales but tight gas sands are much better economics, and that’s why we’ve made the choices in place like the Panhandle and East Texas.

On the service cost side, we’re seeing some pressure from the service companies in 2010, we would project a 5% to 10% increase overall in our estimates for 2010. We are somewhat insulated from rig prices with our rig ownership, we see most of the pressure coming from pressure pumping services, fracs, tubulars and directional drilling in 2010. Not to say this is justified in current gas prices but the recent service company consolidation, as we’ve said we’ll work the pressure prices. So we enter 2010 well positioned in terms of the asset portfolio, much more streamlined growth and cost structure, all sponsored by our past conservatism. Our spending is not a function of our asset quality or economics but by our choices, our options to achieve the best risk-weighted rate of return.

Now let me turn it over to J.C.

J.C. Ridens

Thanks, Craig. First to comment about our 2010 capital program. 2010 approximately 75% of our capital will be spend in our three core areas with the focus on horizontal drilling. During the fourth quarter, we increased our operated rig count from 7 to 12; currently we are running 23 rigs, 18 of which are in our core areas, and 11 that are drilling horizontal wells. We continue our mechanical successes rate of 100% on horizontal wells and I’ll put that record up against anyone’s. We continue the highly successful horizontal progress in the Granite Wash during the fourth quarter. Our first four wells continue to perform far in excess of our initial expectations. To date our four completed wells have averaged IPs of 30 million cubic feet equivalent per day and the largest IP recorded in the fourth quarter has been 37 million cubic feet equivalent per day and we got that from two wells.

60% of that total was in combined hydrocarbon liquids, both free condensate and NGLs. We breakout all hydrocarbon components because our contracts allow us the option to process NGLs. These are not keep-whole contracts. We take our gas and NGL products in kind. These contracts further add to the value chain, in that the liquids we separate and process, we get paid for. We have three wells in various stages of completion currently. All of these wells have 4300 flip approximate laterals with 10 frac stages.

Our budget for the Panhandle this year is approximately $152 million with three rigs concentrating on horizontal Granite Wash wells, and one rig drilling both horizontal Morrow and Granite Wash wells. Additionally, we are participating in four non-operated wells. They are providing further data points on the horizontal Granite Wash and Atoka formations.

Shifting to the Haynesville. We just finished the installation of the amine unit that will service our first Sabine Parish well. This well has previously been curtailed to about 5.5 million cubic feet per day due to CO2 levels that exceeded pipeline specifications. The amine unit will allow us to flow this well on expected 15 million cubic feet per day rate.

Our second well on the area is currently drilling, and notably there have been several successes reported in the southern end of the play in several counties in East Texas and (inaudible) in Harrison County, Texas as well. We have an additional well down in Woodardville and Red River Parish, not to be frac-ed this week. Currently we have two other wells that are drilling in this field.

Our budget for the area in 2010 is approximately $162 million. The bulk of which is for or three rig program drilling horizontal Haynesville wells, both in North Louisiana as well as East Texas. We will also have one rig drilling horizontal Cotton Valley wells.

In Canada, we have seven to eight rigs running. We are doing that in advance of breakup and our plans here is to spend about $168 million this year. Our current activity is focused on the Deep Basin and that includes in-fill programs under way at Wild river and DB.

Regulatory approvals for the down spacing and was approved in Wild River last year and we are taking advantage of that along with the revised role to program which in sense us to drill vertical deviated or horizontal wells. In addition to the revised royalty program, there is also a drilling credit in Alberta of $200 per meter and that favorably impacts the Rate of Return for these programs. At EVERYONE, we were drilling horizontal point oil wells and we’ve seen IPs the size 210 barrels per day from our short-radio horizontals. We’ve also decreased cost to these wells in 2010 by eliminating the intermediate casing and that’s improved the rate of return on this program.

A portion of our other capital for Canada is Fort Quebec. We will be shooting seismic as soon as the snow clears in advance of our next horizontal well. The excellent data point that was just released from an industry world further, demonstrates the evolution of horizontal technology applications in shale-place particularly here. We were the first mover in this plant and just as others have gone to school on our work we now have the opportunity to do the same. As we said earlier, our large acreage position in Quebec has excellent term, a favorable royalty and tax regime and this combined with a premium gas market results in an enviable position for Forest.

Finally, let’s discuss acreage acquisition in 2009. While we decreased capital spending through the dropper we continued to add acreage at favorable prices in our core areas as well as adding some acreages into some new areas. We acquired approximately 150,000 net acres in 2009 for an average price of just over $300 per acre. This acreage will provide for some immediate opportunities in 2010 as well the out years. And of course, a lot it adds to our horizontal inventory which is has become a driver for the company.

At our Analyst Conference, March 18th, we will present detailed updates on our operations in the core areas and we look forward to seeing you all there.

Operator, we are now ready for questions.

Question-and-Answer Session


(Operator Instructions) Our first question comes from the line of Dave Kistler with Simmons & Company.

Dave Kistler – Simmons & Company

Good afternoon, guys. Craig, you were talking little bit about service cost and the uptick that appears to be taken place there as the rig count kind of moves up on horizontal directed side of things, service intense deeper well going up. Previously in your comments you mentioned that you were going to lock down service cost you benefited by not doing it in 2009. Can you talk a little bit about your thoughts on locking them down at this point?

Craig Clark

Well, obviously for rigs we wouldn’t do that and haven’t in the past because of our ownership but in terms of discount agreements for certain services we’ll be doing that for 2010. You never catch the bottom; it’s just with your works more predictable. And secondly, in terms of you service cost intensity I would probably reiterate that it’s more on a completion side and the drilling side this time.

Dave Kistler – Simmons & Company

Okay, that’s helpful. Thinking a little bit about the Granite Wash, as you guys kind of start working your way through that, targeting a variety of different formations, can you kind of talk about how you are strategically doing that? It looks – I don’t know if it’s for sure to-date you’ve only been targeting one particular area, but can you guys give us some more color around that?

Craig Clark

I think it's safe to say, Dave, between us and the industry out there, you are seeing other formations within the Granite Wash other than some of the formations that were tested initially that are now being opened up. That’s one of the great things about having an OBO component or operated by others because we have hidden data points from that as well. And I think that something that will be key in 2010 is, you will see delineation of this play, and it won't just be from a geographic standpoint, it will be from a vertical standpoint. So, at this point I’ll tell you that we are seeing more than just the initial zones that everybody reported being tested, and we’ll have an update for you next month.

J.C. Ridens

Dave, the 400 well database that we’ve basically drilled or acquired, the drilled is spread throughout all four counties. And I can't tell you which zone will be which were. We have actually done two zones as industry so far, one in the Granite Wash and one in the Atoka, and we participated in those wells as well. But the 400 wells are spread throughout the map; in fact three rigs are down south in Wheater Henfield [ph] and one’s up in north. So we are spreading out the lease and the verticals to guys.

Dave Kistler – Simmons & Company

Okay, and then just jumping a little bit away from stuff you talked about on the call, another company was out this morning putting up some results from the Utica Shale, and that’s something that we haven't heard about from you guys for quite awhile. Any update relative to that, anything intriguing about that? I am not even sure if you’ve seen that news yet today.

Craig Clark

Yeah, we have seen that news, and yes it's intriguing, because I think that it lends further validation to the play obviously. That’s a impressive rate that was reported on that well. And as I said in my comments, I think that that is reflective of, I’ve seen the evolution of technology within a plays, we did them, we start this process and then others join us. Obviously, we are going to ramp that learning curve up more as we have said throughout this year. We have spent the year taking what we learned previously back to the lab and looking at ways to enhance our future efforts, and I think that what we saw today shows that the plays got some legs to it and some excitement to it.

J.C. Ridens

And yes, we were aware the well engineered us.

Dave Kistler – Simmons & Company

Great. I appreciate that color. I’ll let somebody else jump on.

J.C. Ridens

Okay. Thanks, Dave.


Our next question comes from the line of Scott Hanold with RBC Capitals Markets.

Scott Hanold – RBC Capitals Markets

Good afternoon.

Craig Clark

Hi, Scott.

Scott Hanold – RBC Capitals Markets

Hey, could you speak with the Utica for a bit because obviously I think you all have bought about 270,000 net acres yet and. Remind me where we are at in the lease terms, if I remember right they’re pretty long. And can you kind of give us an idea of where that industry well was drilled relative to your acreage?

Craig Clark

Well, the acreage doesn’t run north, south, it runs along the river, and they’re blocks adjacent to us as you can imagine with those large blocks. Most of our acreage is concentrated in three large blocks, and there is this as well. On the lease terms they have form outs, I believe the competitor, so they have some obligations that have required them to do constant activity, I believe. Our terms do not – we’ve met those obligations, and I think we are in year two or three of ten year leases, so we got lots of time. Needless to say we did all the work first and for the benefit of the industry, and now get to – get to somebody to reciprocate there, the first well they have announced, these are the first non-Forest horizontal drills out here -- was drilled based on the release by one of our blocks, one of them by acreage, they blocked a PUD so I do not know the mileage, but its obviously pretty close.

Scott Hanold – RBC Capitals Markets

Okay. Okay. And when you look at your activity, I think J.C. did you say you have been shooting seismic in that area this year. I mean, what else can we see from Forest in 2010 and in the year to come?

J.C. Ridens

Well, after we get the seismic shot and acquired and then analyzed then our plan is to follow it up with oil. So I am thinking that in 2010 you ought to see another well of out of this, provided that we get snow cleared and get the seismic acquired in a timely fashion.

Scott Hanold – RBC Capitals Markets

Okay, very good. All right, thanks guys.


Our next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer – Goldman Sachs

Thank you. Good afternoon.

Craig Clark

Good afternoon, Brian.

J.C. Ridens

Good afternoon.

Brian Singer – Goldman Sachs

I am wondering if you could add up a bit more color on that – on a deep basin. It’s been area you have had for some time, and if you could just add beyond the changes and some the stimulus royalties, what has improved and what does that means for your overall Canadian production, oil and gas for this year?

Craig Clark

Well, we obviously gave them more capital in part because they didn’t have much in the past two years because of the taxes, and we gave them a lot because we announced the down spicing spacing and verticals and multi-zones and places like Wall River and then AV with oil and that was a natural phenomena here regardless of what we think can happen in the deep basin from a horizontal or deviated standpoint.

So, vertical well economics there actually may look better than just about any where else because of the lack of taxes. So they got to play catch up on capital including, I think, about $20 million pipeline.

In addition to that, we've been public not only saying the high gas sand and carbon – has had potential to on a deviated standpoint with the new fracs, new completions, which is nothing more than what happened in East Texas in the Cotton Valley, which people were caught on to and obviously let us to do the Buffalo Wallow which is obviously exceeded our expectation as you know, Brian.

We would like to replicate that into deep basin throughout what our acreage position and we gave you more capital to do that this year, including pipeline infrastructure. We’ll hope to highlight that at the Analyst Conference, but clearly we would like to replicate the success in tight gas and covenants regardless of the new flavor of the day shale up there. Clearly, we would like to do that starting with the vertical work we have done in both foot hills and the deep basin.

Brian Singer – Goldman Sachs

And what does that mean for overall Canadian production this year --?

Craig Clark

We have not yet Canadian production separate but it’s a key cog in the growth that we projected for the entire company. I think all three areas of East Texas, North Louisiana, Buffalo Wallow over the Panhandle and they all contribute up the same rate. I will tell you that, the growth is driven by Buffalo Wallow because those wells are so good, but clearly Canada pulls it weight in terms of growth. It shrank quite a bit after the property sales, so it’s percentage will be higher, but I don’t know the exact number.

Brian Singer – Goldman Sachs

Thank you. And lastly, what are your thoughts on the Bossier Shale and the potential for that overlay your Haynesville acreage?

Craig Clark

Well, we have been saying and told them so. Again, it’s an arbitrary designation. It could be that some of the wells that are -- are well to the south kind of set things up, but its Haynesville. But I think on the Texas side, the nomenclature gets – we have got 800 foot of shale and 1000 foot sections still available to take a look at, at Arkoma and Texas side. It’s possible that even some of the wells that we have been reading about in St. Augustine and Shelby are actually technically in the Bossier, but I think the designations arbitrary except that we will, as others will expand, uphold, because there is 800 more foot of gas-bearing shale above us, and I would think our acreage on the Texas side is just as prospective anybody else’s.

Brian Singer – Goldman Sachs

Thank you.


(Operator Instructions) I’m showing no further questions in queue at this time. I will turn the conference back over to Mr. Redmond for any closing remarks.

Patrick Redmond

Thank you. This concludes our conference call. I want to thank everyone for their interest and participation in our call. If you have any further questions, please feel free to contact us. We look forward to seeing you at our Analyst Conference on March 18th. Thank you.


Ladies and gentlemen this does conclude today’s teleconference. Thank you for participating. You may now disconnect.

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