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Forest Oil (NYSE:FST)

Q3 2013 Earnings Call

November 05, 2013 9:00 am ET

Executives

Larry C. Busnardo - Director of Investor Relations

Patrick R. McDonald - Chief Executive Officer, President, Director and Member of Executive Committee

Victor A. Wind - Chief Financial Officer, Executive Vice President, and Treasurer

Analysts

Pearce W. Hammond - Simmons & Company International, Research Division

Michael Hall

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Biju Z. Perincheril - Jefferies LLC, Research Division

Sean Sneeden

Patrick Lee - Wells Fargo Securities, LLC, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Forest Oil Third Quarter 2013 Results Conference Call. My name is Sue, and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I would now like to turn the call over to Larry Busnardo, Director of Investor Relations. Please go ahead, sir.

Larry C. Busnardo

Thank you, Sue, and good morning, everyone. Thank you for joining us for the Forest Oil Third Quarter 2013 Earnings Conference Call. Joining me on the call today is Patrick McDonald, Forest's President and Chief Executive Officer; and Victor Wind, our Chief Financial Officer. If you have not already done so, please go to our website at forestoil.com to obtain a copy of our earnings release. A replay of this call will be available through November 11, as described in our press release issued yesterday afternoon.

Before we begin, 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 measure calculated in accordance with GAAP will be available on our website and can be viewed by clicking on the Investor Relations tab, then Non-GAAP at forestoil.com.

Forest's comments today will include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are subject to a number of risks and uncertainties that may cause the actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Forest's earnings release and in Forest's public filings made with the Securities and Exchange Commission.

With that, I will turn the call over to Pat McDonald.

Patrick R. McDonald

Thank you, Larry. Good morning, and thank you for joining us today. I'll start with a review of the third quarter and then touch on operational highlights, after which, I will turn the call over to Victor Wind for a summary of the financial highlights for the quarter.

During the third quarter, we made good progress in the development of our Eagle Ford asset. This led to a significant jump in our Eagle Ford production volumes during the quarter. Importantly, we remain on track to meet our goal of averaging 2,800 barrels a day equivalent from the Eagle Ford in 2013, and we believe our Eagle Ford volumes will more than double in 2014 to over 6,000 BOE per day, based on an 80-gross well, 40-net well development plan, which we communicated earlier this year when we announced our joint venture in the Eagle Ford.

We made further progress in lowering our Eagle Ford drilling costs as we begin to capitalize on the synergies associated with pad drilling and more efficient and effective completions and drilling well construction. We see the potential for additional improvement in this area during 2014.

We recently announced the sale of our Texas Panhandle assets in early October for $1 billion. This will be a tax-free event for Forest. We believe the transaction remains on track to close later this month. The Texas Panhandle sale is a transformational event for the company, which positions Forest with a sharpened operational focus heading into 2014 and a strong platform for oil growth, underpinned by our Eagle Ford asset.

Consistent with what we have communicated in the past, we will use the net sale proceeds to reduce our outstanding debt.

I would like to thank all of the Forest employees who contributed to the success of this divestiture, and we look forward to closing that transaction later this month.

In terms of third quarter operational activity, we continue moving toward the completion of the acreage holding phase of the Eagle Ford development program. The focus of our drilling, to date, has been to delineate the field, hold the acreage position, and we are beginning to prepare for the transition to full-scale development drilling, and we'll concentrate on the most productive areas of the field during 2014. In this regard, we have made considerable progress toward the goal of holding an aggregate of 55,000 gross acres and 27,500 net acres. We currently have approximately 70% of the target acreage held through our drilling efforts, and we expect the remainder to be held by mid-2014.

We are currently carrying an inventory of 688 gross, 344 net locations based on an 80-acre spacing development program. This inventory of drilling provides a current pace of drilling of 7-year drilling inventory. Once the acreage holding phase is complete in mid-2014, we will begin development drilling. We are in the process of evaluating and determining the optimal drilling density and well spacing for each of the areas of the field. We believe that some offset operators have successfully tested downspacing to 40- to 60-acre spacing. And obviously, if we are successful with that level of spacing, it would increase our drilling inventory.

In addition, we are also currently actively seeking additional land acreage near our better well results. We -- during the quarter, we completed a total of 18 gross, 9 net wells. 12 of the wells, 6 net, were completed and came on production at a 30-day average gross production rate of 542 barrels of oil equivalent per day. These areas were located throughout the acreage position in the field. Within this group of wells, 3 of the more recent wells had 30-day gross production rates of over 700 BOE per day, which is very encouraging as we begin to understand and develop the field. The remaining 6, or 3 net wells, were located in the northeast section of our acreage position and had average 30-day rate of 229 BOE per day.

The concentration of wells drilled in this area, were the result of the expiring lease -- lease expirations and were drilled in conjunction with the acreage holding program. This is a relatively small portion of our overall position, and we do believe that this area of the field is capable of economic development as we begin to understand the reservoir characteristics in the shallower section and optimize the development through a lower well cost designs and well completion programs.

We are currently operating more efficiently in the Eagle Ford through a combination of decreased drilling and completion times, more targeted completion design and capitalizing on operational synergies associated with pad drilling. Our recent 4-well pad was completed in 49 days compared to an average -- a previous average of 56 days, a 13% decrease in completion time. The average cost to drill and complete wells during the third quarter averaged approximately $5.75 million. This is 10% lower than the wells drilled in the second quarter and 18% lower than the wells drilled in 2012, which were an average of $7 million. We expect to see further improvement on the drilling cost side during 2014, as our centralized production facilities and infrastructure become operational. We believe this will result in even further reduction in cost, once the full-scale development drilling commences in 2014.

The ability to drive down well cost, sequentially, has resulted in improved rates of return being generated from these wells. We are projecting the same pace of activity in the Eagle Ford program during the fourth quarter of 2013, but given the fact that well completions are geared toward the second half of the quarter, we are currently projecting our Eagle Ford volumes to increase slightly over the 3,300 BOE per day, which were produced during the third quarter.

In regard to our Ark-La-Tex region, we believe this asset is -- deserves greater attention within the company, and we've begun to put geological and engineering teams together to fully evaluate the acreage and identify the scope of the opportunity set. Forest has a large acreage position of approximately 162,000 net acres in what we refer to as the Ark-La-Tex area, Arkansas, Louisiana and East Texas, including the Arkoma Basin. Much of this acreage -- vast majority of the acreage is held by production, which leaves us with minimal drilling commitments. And in fact, 85% of the production is currently operated by Forest. We believe this asset provides repeatable, predictable drilling and completion opportunities in multiple horizons. Our recent activity has focused on the high liquids yield Cotton Valley formation and other oil and liquids-rich horizons within the East Texas portion of the acreage. During the quarter, we completed 2 liquids-rich Cotton Valley wells, which had average 30-day production rates of 10 million cubic feet equivalent per day, comprised of 38% liquids. This is consistent with our previous results, and among the 5 wells we have completed this year, we have achieved average 30-day production rate of 9 million cubic feet equivalent per day with approximately the same liquids composition. We will continue to operate 1 rig in this area which we believe will contribute to relatively flat production going forward.

I'd like to turn the call over to Victor for his section of the presentation.

Victor A. Wind

Thanks, Pat. I'll begin my comments today with a short summary of this quarter's results and then address the updates we provided in the release in terms of our fourth quarter outlook.

Regarding third quarter results, we reported adjusted earnings of $0.06 per share, adjusted cash flow of $0.47 per share and adjusted EBITDA of $85 million. While these results came in below sell-side consensus estimates, the variances can be attributed primarily to 2 items: lower-than-expected production volumes from our Panhandle properties; as well as the widening of our oil price differentials, primarily due to the reduction in the LLS premium over NYMEX WTI.

Our third quarter net sales volumes averaged 209 MMcfe per day, which was 1% lower as compared to the second quarter sales volumes of 211 MMcfe per day. The sequential decline in quarterly production was primarily due to lower-than-forecasted production volumes in the Texas Panhandle.

As I noted on last quarter's call, our expectation was for the Panhandle production to remain flat for the remainder of 2013. However, 2 Missourian Wash wells completed in the third quarter came online at less-than-forecasted rates. This negatively impacted total equivalent production, as well as our anticipated growth in oil production, as a percentage of total sales this quarter.

With respect to our realized oil differentials, our differential widened to $2.88 per barrel from $0.53 per barrel last quarter. This resulted in a realized oil price, before the impact of hedging activities, of $102.94 per barrel. The quarter-over-quarter increase in our oil differential was driven by an approximate $5 decrease in the LLS premium to WTI this quarter. Note that more than 50% of our oil, including our Eagle Ford and East Texas oil production, is sold on an LLS-based price.

So moving on to the cost side of the equation. Our total cash cost decreased 4% this quarter to $64 million or $3.31 per Mcfe from $66 million or $3.46 per Mcfe in the second quarter of 2013. The sequential decrease was attributable to a 19% reduction in G&A cost as well as a 2% decrease in production expense. Looking ahead, we expect further reductions in total cash cost following the Panhandle sale, somewhat stating the obvious in terms of reduced LOE, but we also expect a sizable reduction in G&A starting next year and a significant reduction in interest expense, which I will address later.

Our total capital expenditures for the quarter came in at $81 million, which was up slightly from last quarter, as overall drilling activity increased with the addition of a fourth rig in the Eagle Ford play and the overall timing of our drilling and completion activity.

Year-to-date, our total capital expenditures were $279 million and has been allocated between our various regions, consistent with our 2013 budget for the year, with 45% directed to the Texas Panhandle and 55% directed to the Eagle Ford and Ark-La-Tex assets. Based on our total -- expected total capital expenditures for the fourth quarter of $80 million to $85 million, we are projecting that our total CapEx will be within our 2013 full year guidance range of $355 million to $375 million.

Regarding our long-term debt, Forest exited the quarter with total debt of $1.62 billion, which represented a $15 million decrease from last quarter. This was attributable to Forest receiving proceeds from the Permian Basin acreage sale that we announced in early September.

Looking forward to the fourth quarter, as Pat mentioned earlier, we plan to use the net sale proceeds from the $1 billion Panhandle divestiture to reduce our outstanding debt. However, we will not specify today which components of our debt will be targeted for reduction. Bottom line though, we do not plan on sitting on cash for an extended period of time, and with only $115 million drawn on the credit facility as of September 30, you can assume the majority of our debt reduction will be targeted towards fixed-rate debt, which will result in a significant interest savings going forward.

I'd like to now address the fourth quarter updates we provided in the press release. Incorporating the continued impact of lower-than-forecasted production from the Texas Panhandle into the fourth quarter, both from third quarter well results and the deferral of several completion projects at the request of the buyer, we expect our net sales volumes to average approximately 200 to 205 MMcfe per day during the fourth quarter, approximately 60% of which will be natural gas and 40% liquids. Note that fourth quarter production guidance of 200 to 205 a day assumes a full quarter of contribution from the Texas Panhandle assets.

The other item we updated for fourth quarter was our expected oil differentials due to the weakening of the LLS premium over WTI, relative to where it was when we issued guidance this year. At that time, the LLS premium was expected to be over $10 per barrel in the fourth quarter. As of today, with nearly 2 months of LLS premium already minted for the fourth quarter, the LLS premium is forecasted to be approximately $2. Accordingly, we updated our total expected oil differentials in the fourth quarter to average $6 to $7 per barrel below WTI.

While I'm on the topic of commodity prices, I'd also like to remind everyone of our hedge position for 2014. We currently have 3,500 barrels a day -- barrels of oil per day hedged at $95.34 and 80,000 MMBtu per day hedged at $4.34, which together will protect a good portion of our expected 2014 EBITDA.

Finally, before I hand the call back over to Pat for closing remarks, I want to let everyone know that we plan to release our 2014 guidance shortly after the closing of the Panhandle sale on November 25. This release will also include detail on how the divestiture will impact various reported items for the fourth quarter, such as production, LOE, DD&A and other items.

So with that, I'll hand the call back over to Pat. Thank you.

Patrick R. McDonald

Great. Thanks, Victor. I'd like to review and summarize our key points from today's call.

Firstly, the sale of the Texas Panhandle asset will result in significant reduction in debt for Forest. Forest will be thus positioned -- better positioned post the transaction to execute on its growth opportunities, primarily in the Eagle Ford. We continue to make excellent progress in the development of the Eagle Ford position and will move to full-scale development drilling during 2014, which we believe will result in further scale, capital efficiency and growth in production, reserves and cash flow.

We have made excellent progress in reducing our Eagle Ford well cost, and we project even further improvements versus 2013 cost structure. Our current Eagle Ford inventory provides growth opportunities beyond the next several years. We are also currently seeking additional opportunities to expand our acreage position. All of this will lead to significant growth in oil volumes for 2014. We expect our Eagle Ford oil volumes to more than double in 2014 to over 6,000 barrels of oil equivalent per day, which will translate into significant growth for the company-wide volumes as well. And as Victor said, we will provide 2014 guidance following the close of our Texas Panhandle transaction. Thank you, all, and we look forward to hearing your questions.

Sue, we're ready for questions now. Thanks.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Pearce Hammond, Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

You mentioned in the press release that while you're currently at 4 rigs in the Eagle Ford, you can prosecute your '14 program which is 3 rigs. Can you provide some color around rig efficiency gains that you're experiencing right now?

Patrick R. McDonald

That's correct. We'll probably go to -- we intend to go to 3 rigs later in the end of the fourth quarter and into 2014. We're just drilling the wells much faster from spud date to date of first production. We've reduced that time significantly.

Pearce W. Hammond - Simmons & Company International, Research Division

And then on a positive news on the lower well cost quarter-to-quarter in the Eagle Ford, what were the major contributors to that decline? Is it just more of the rig efficiency gains?

Patrick R. McDonald

It's partially due to the reduced number of drilling days, but we're also reducing our overall completion costs, faster drill-out of plugs, overall, just more efficient operations as our crews and our teams get familiar with our well completion programs. So it's more or less in all areas, mainly, in the time spent to drill and complete the wells.

Pearce W. Hammond - Simmons & Company International, Research Division

Great. And then on this northeast acreage, where you had some wells that weren't quite as strong as your other wells from the Eagle Ford. With that acreage, do you intend to let some of that expire? Or will you hold it and just hope to be able to reduce your well cost to make that economic?

Patrick R. McDonald

Well we certainly believe that we can reduce our drilling and completion costs to make that area economic. There are some areas of that part of the field that we will likely let expire, but not a significant amount, nor will it put a significant dent in our overall 55,000-acre gross acreage holding plan.

Pearce W. Hammond - Simmons & Company International, Research Division

If you had to put a percentage around the total -- of your total gross that might expire, what do you think that number might be?

Patrick R. McDonald

It's less than a couple thousand acres gross.

Pearce W. Hammond - Simmons & Company International, Research Division

Okay. And then last one for me, in your East Texas Ark-La-Tex area, do you think you have any prospectivity to the [indiscernible] line?

Patrick R. McDonald

We've known -- I've been aware of that play. Our acreage is not exactly in the heart of that play, so we don't really have a very good blocky position. But it's still under geological evaluation. All these plays seem to develop over time, as people begin to understand them better. But I will say, we -- I couldn't consider our acreage to be in what is presently known as the heart of the play.

Operator

And your next question comes from the line of Michael Hall, Heikkinen Energy Advisors.

Michael Hall

I was wondering a few things in the Eagle Ford. First, if you could talk through -- what sort of variability kind of completion design did you have in the wells that were brought on during the quarter, the part of this one JV?

Patrick R. McDonald

I wouldn't describe it as variability. We continue to fine-tune the completion program. We more or less believe in the core area of the field. We've got our completion design pretty well figured out in terms of number of stages, spacing of stage intervals, proppant size, pumping rates and completion procedures. That's been one of the main contributing factors to the reduction in well cost. In these other -- in the less, what we call less productive areas of the field, we're currently evaluating different contingent schemes, which we believe will result in considerably lower well cost for those areas and result in economic development of those particular areas. But at the moment and into the bulk of our program in 2014, we'll be focused on the more productive areas of the field.

Michael Hall

Okay. And then on your Eagle Ford acreage, what is the thickness profile? How does that trend, if you will, maybe from southwest to northeast to just [indiscernible] thickness of the Eagle Ford?

Patrick R. McDonald

I can't quote exact formation thicknesses. That's a relatively widely known geological formation thickness as we go from the northern part of Gonzales County, south into the main part of the current's [ph] trough.

Larry C. Busnardo

Michael, this is Larry. It's probably on the order of 80 to 100 feet that kind of on average throughout our position there.

Michael Hall

Okay. And do you think -- there are some positive about the Eagle Ford developments of late. Any commentary or thoughts on potential prospectivity of completing both the upper end or lower Eagle Ford?

Patrick R. McDonald

Yes, we're certainly aware of that play concept, and we believe that, that may exist across our acreage position. It will largely depend on -- as you observe the thickness of the Eagle Ford and the relative position, up-dip shallow versus down-dip deeper.

Michael Hall

Okay. And then last on the Eagle Ford. My end of it, there's been obviously some good down-spacing test throughout the industry. Any plans of your own to test down the 40- to 60-acre spacing and patterns and along those lines in 2014?

Patrick R. McDonald

I think, Michael, we'd more characterize it as we're currently reservoir modeling and understanding the optimal spacing for the different areas of our field. We're not ready to talk about exact spacing in terms of number of acres or distance between laterals, but it is currently an investigation that's underway and hopefully, we can -- during the -- beginning early part of 2014, we'll have a much better sense of how to develop the various -- the different areas of the field as we go from shallow to deep, from north to south.

Michael Hall

Okay. And then last one on my end is just thinking about maybe broadly, directionally the Ark-La-Tex region in 2014. I think you talked about running 1 rig there. How does that -- does that [indiscernible] trying to keep production flat? Or...

Patrick R. McDonald

We do believe 1 rig can keep production flat. Our goal here as we go forward and sort of the newly position for us, we'd like to accelerate our drilling activity there. It's all part of the capital allocation, capital budgeting process. And at the moment, obviously, the Eagle Ford is going to command the bulk of our capital resources for 2014.

Operator

And your next question comes from Amir Arif, Stifel.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

I was just curious if you have tested the HiWAY fract shed [ph]. I thought you were going to try to test them in the third quarter.

Patrick R. McDonald

We do. We have a handful of HiWAY frac wells. We're still not able to say one way or the other whether or not it's the right thing for our field. We've conducted some of our completions using slight modifications of the HiWAY frac as well as our own designs with input from our partner, and we're encouraged by all of those results.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Could you just give us a little more color on the results in terms of CapEx increase versus IP or is it more the EUR you're concerned about?

Patrick R. McDonald

Well, I guess, we're, overall, just looking at the rate of return on the wells. I think it is safe to say that the HiWAY fracs are more expensive than the conventional frac work that's being done. And so that's all being baked into our well design and completion cost. They're largely depending on where we are within the field.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay, okay. And you made comments about expanding acreage position in the Eagle Ford. Would that be done in conjunction with Schlumberger in terms of you just take 50-50 of new acreage and if you can quantify how much you're looking at in the next 12 months or so?

Patrick R. McDonald

Yes, there is a contract area or area of mutual interest that governs the joint venture agreement. So to the extent that acreage is acquired within that outline, it would be shared with our partner.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay, and it would be no promote on that? So I'm taking it'll be straight 50-50?

Patrick R. McDonald

Yes, that's correct.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then just a final question on the -- on your 60,000 acres in the Reeves, Pecos County. I haven't heard much about your plans or activities for that. Can you just give us an update on what you're thinking there and when you have to do something before exploration?

Patrick R. McDonald

Yes. We're watching offset operator competitor activity come toward us as the development moves from north to south. So we're encouraged by that. We're also continuing to show our land position to industry partners. And as we said before, there's more interest in our acreage position now than there was a year ago, let's say. The focus is to try to create value out of that asset whether it's through a joint venture or outright sale.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. Is there a sense of timing in terms of when the explorations would start it in terms of when you need to get something done there?

Patrick R. McDonald

There's a high sense of urgency around here. We need to get something done right away. Our acreage position doesn't really start to fall apart until '15 and even into '16. There is time and runway for a possible development program.

Operator

And our next question comes from Biju Perincheril, Jefferies.

Biju Z. Perincheril - Jefferies LLC, Research Division

A couple of questions on the Eagle Ford. I was wondering, the Northeast area that you talked about with lower rates. Is there any geologic feature that isolates that area? Or is it essentially that as you're going in that direction, you're gradually losing reservoir pressure and thickness?

Patrick R. McDonald

Yes, sir, I think your comment is -- your observation is correct.

Biju Z. Perincheril - Jefferies LLC, Research Division

It's not any geologic feature?

Patrick R. McDonald

No, it's not a geo hazard or anything other than just normal progressive shallowing and less depth.

Biju Z. Perincheril - Jefferies LLC, Research Division

Got it. And then what was the well cost for -- I think it was 6 wells that was completed in that area, and did those wells have the typical completion that you're using across your acreage?

Patrick R. McDonald

Lower cost, some of the wells were much lower cost and were drilled and completed using the alternate completion design, and we're very encouraged by the cost and the results based on that particular well design.

Biju Z. Perincheril - Jefferies LLC, Research Division

Can you give us some sense of how much lower you were able to get there?

Patrick R. McDonald

We're just not ready to talk about that just yet. We've got a limited set of data points. And as we start to look at that area of the field in 2014, we'll continue to revise and refine our well completion program for those -- that area of the field, but I have to say, we anticipate that it will be a significantly lower cost than the main area of the field.

Biju Z. Perincheril - Jefferies LLC, Research Division

Okay. And then regarding your comments about East Texas and serving of increased activity there, is your plan to sort of maintain that 1-rig plan there and what you need to see to perhaps increasing activities there?

Patrick R. McDonald

Yes, our current plan is to maintain 1 rig in the East Texas area, principally, Cotton Valley -- liquids-rich Cotton Valley. And we're trying to come up with ideas and ways in the back half of '14 to allocate some more capital or find a way to increase our level of activity.

Operator

And our next question comes from Sean Sneeden, Oppenheimer.

Sean Sneeden

Okay. Could you talk about just what you're thinking about in terms of your current drilling inventory in terms of years? And then I know it's still early, but you're doing a good job cutting off there in Eagle Ford [indiscernible] provide any sort of ballpark figures in terms of what you're seeing in IRS currently?

Patrick R. McDonald

We -- you're fading out, I'm sorry. What -- the second part of your question was IRS? What was the first part, please?

Sean Sneeden

Just your drilling inventory.

Patrick R. McDonald

Oh, the drilling inventory, I mean, just the math of it, is 688 gross locations on the 80-acre spacing with our current 3-rig program, and drilling efficiency is a 7- or 8-year inventory of locations in the Eagle Ford. And in terms of our rate of return, our target rate of return is in the mid-30s on these wells. And obviously, we do everything we can every day to try to improve that. The key is continuing to drive the cost down and through the completion designs, increase the productivity of wells.

Sean Sneeden

Okay. And that's helpful. And then just kind of on -- can you talk about, generally, what you're seeing in terms of the availability of acreage there, kind of around your core area?

Patrick R. McDonald

Well some of the acreage in and around us is held by production, and others is available in one way, shape or form, whether it's lease expirations or negotiated transactions. So we're actively continuing to infill bits and pieces within the field and then also expanding outward.

Sean Sneeden

Okay. Would you say it's more -- just kind of getting a sense of the size there? Is it more bolt-on type of opportunities or do you feel like there are larger packages available?

Patrick R. McDonald

I'd say that they're probably be described as bolt-on, complementary, kind of expanding concentrically outward. There are some larger positions, but those will be more challenging and less frequent opportunities for us.

Sean Sneeden

Okay, that's helpful. And then just kind of lastly, I know you said you couldn't say a whole lot on your debt reduction plans, but can you just give us a sense in kind of broad strokes on what your relative priorities are there? Is it just -- are you targeting overall rate or maturity? Or can you talk us through how you might think about that?

Patrick R. McDonald

Well, Sean, with respect to rates, in terms of our existing fixed-rate debt, they're pretty close, and same thing with maturities and as far as outstanding tender goes. We're in the process of finalizing our plans right now. We'll announce them at the appropriate time. In the meantime, we really can't comment how we're going to proceed with respect to debt reduction. The only other thing I would note, like I did in my prepared comments, is that there is only $115 million outstanding on the facility, so you can assume a large majority of the reduction is going to be in the form of fixed-rate debt.

Sean Sneeden

Okay. And are there any requirements under your credit facility that you have to pay that down with the proceeds or can you use the full $1 billion or so to pay down bonds?

Patrick R. McDonald

Yes, it's more under the indentures we have to use proceeds from asset sales to reduce debt.

Operator

And your next question comes from Gufa Babar [ph], Nomura Securities.

Unknown Analyst

Two questions, one is a follow-up to the previous question. Is there anything particular in terms of requirements that's holding back your decision on announcing how you want to use the proceeds? And my second question is related to kind of thinking about 2014 CapEx. I just want to kind of run through the math. It seems like you guys should be able to hit a CapEx run rate well below $300 million, and if I'm kind of thinking right in terms of orders of magnitude for that.

Patrick R. McDonald

Right. Well, with respect to your first question, I mean, I can only basically repeat what I just said that we're in the process of finalizing our plans, and we'll announce them in the appropriate time, which will be shortly. With respect to our 2014 capital plan, we'll include that in our guidance, which we said that we're going to release after the Panhandle sale. But just broad strokes, you can assume an 80-well program in the Eagle Ford, which our costs, with respect to on a per-well basis, and then if we drill 6 to 8 wells in the East Texas, your assertion of under $300 million is directionally correct.

Operator

And our next question comes from the line of James Spicer, Wells Fargo.

Patrick Lee - Wells Fargo Securities, LLC, Research Division

This is Patrick Lee for James Spicer. Our question's have been answered.

Operator

And your next question is from William Adams [ph], [indiscernible].

Unknown Analyst

Just wanted to ask you, I know you don't have specifics for the budget for next year, but can you give us an idea of where longer-term your financial metrics, like some kind of debt-to-EBITDA ratio, and do you think eventually you will be able to keep your spending in line with cash flow? Just some comments on that.

Patrick R. McDonald

Yes. First response, I guess, in terms of where we'd like to see ourselves in terms of debt-to-EBITDA, I think the mid-2s would be a comfortable position for us, which would be in line with our peers. And the other question, yes. I mean, we do see what the growth in the Eagle Ford, eventually, just with the oil growth that we would be closer to a self-funding CapEx program going forward.

Unknown Analyst

Okay. And then have you had any discussions with the rating agencies? What type of response do you think they're going to have with this transaction, this asset sale?

Patrick R. McDonald

They were pleased with the $1 billion number. I mean they see it as a significant deleveraging event. The only thing they really said going against us is just the company size going forward that we're half the size we used to be. But overall, directionally, they're satisfied with the $1 billion proceeds.

Unknown Analyst

Okay. Do you think there'll be any upward adjustment or from this that change the outlook or anything?

Patrick R. McDonald

Could be. I mean, their position is they're going to monitor our progress with respect to Eagle Ford development and growth there. So that's what things are contingent on in terms of change in outlook and potential upgrade.

Operator

I would now like to turn the call over to Larry Busnardo for closing remarks.

Larry C. Busnardo

Okay, thanks, Sue. This concludes our conference call. I want to thank everyone again for your interest and participation. If you have any further questions, please feel free to contact me. Thank you. Have a good day.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.

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Source: Forest Oil Management Discusses Q3 2013 Results - Earnings Call Transcript
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