Forest Oil Management Discusses Q4 2013 Results - Earnings Call Transcript

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 |  About: Forest Oil Corporation (FST)
by: SA Transcripts

Operator

Good day, ladies and gentlemen, and welcome to the Q4 2013 Forest Oil Corporation Earnings Conference Call. [Operator Instructions] I'd like to advise all parties that this conference is being recorded for replay purposes.

And now I'd like to hand the call over to Larry Busnardo, Vice President, Investor Relations. Please proceed, sir.

Larry C. Busnardo

Good morning, and thank you for joining us today for Forest Oil's Fourth Quarter and Year-End 2013 Earnings Conference Call. Joining me for the call today is Patrick McDonald, Forest 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 March 5, 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.

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

Thanks, Larry, and thanks, everyone, for joining us this morning. I'm pleased to announce that we were able to accomplish a number of the strategic goals we set forth for 2013. Our objectives were to accelerate the development of our oil assets, principally the Eagle Ford; improve our operational focus by directing our efforts to the assets where we had the confidence and resources to develop them; and importantly, to reduce the debt level of the company. I'd like to thank everyone at Forest for their hard work and dedication toward the achievement of these objectives.

We announced in April of 2013 a joint development agreement for our Eagle Ford assets, which benefited us by providing the capital required to increase the drilling activity, as well as access to impressive technology, which will pay benefits now and in the future. We were able to significantly reduce the debt of the company through the sale of our Texas Panhandle and South Texas assets, which generated cash proceeds of approximately $1.3 billion. These transactions have laid the foundation for our future growth.

Oil and liquids volume increased over the year as net oil sales volumes grew by 55%. Net liquid sales volume grew 41% compared to 2012, pro forma for divestitures. Our oil reserves grew by 30%, and we believe this trend will continue in 2014. We made major progress in lowering our drilling and completion costs in the Eagle Ford as we implemented more efficient well drilling and completion designs and overall increasing operational efficiencies. We reduced well cost by 15% over 2012, and we see the potential for further significant and sustained improvement in cost and performance -- well performance in 2014.

Our Eagle Ford delineation plan, which we activated in 2013, focused on the holding of our acreage position, the gathering of geological, geophysical and reservoir data and the optimization of drilling and completion techniques as we advance toward the development stage of the program. During the delineation phase, not unexpectedly, drilling results vary depending on the area of the field in which our drilling took place.

The drilling activity that we conducted in 2013 allowed us to gather significant geological, geophysical information, prioritize the future development areas and determine the optimal well drilling completion and fracture stimulation design and techniques. We believe it is important and prudent to conduct early science work to provide us with a better understanding of the reservoir characteristics so that we could determine the most optimal and economic development program. The information we gathered in 2013 will allow us to move forward with confidence in 2014 as we begin the development phase of our Eagle Ford program.

In 2013, we drilled 44 gross, 22 net wells, which had average 30-day rates of 408 barrels of oil per day and include 17 gross, 8.5 net wells that were completed since our last operational update, which had 30-day average gross production rates of 304 barrels a day. Of those, 7 or 3.5 net were drilled as part of 2 separate well spacing and artificial lift pilot projects. And in addition to that, 3 net wells -- 3 gross, 1.5 net wells were drilled in areas where flow rates were affected by increased faulting.

We conducted 2 separate spacing tests to gain a better understanding of the producing reservoir so that we could determine the optimal spacing pattern for the field during the development phase. Based on the initial drilling and production data, we believe the average spacing of 500 feet to 1,000 feet between laterals will be the development configuration for the majority of the field as we go forward.

The wells which encountered faulting were as a result of drilling in an area where our two 3D seismic surveys overlap and where the resolution resulted in reduced imaging of a deep-seated fault complex. Completions in these wells resulted in a high volume of water, which originated from the deeper formations. To mitigate this risk going forward, we're in the process of merging and reprocessing these 3D surveys to more accurately image the fault patterns in this portion of the field. This data will be processed, interpreted and utilized to select drilling locations by the third quarter of 2014.

The southern area of the field is where we plan to concentrate the majority of our activity during 2014, and it is where we have the best well results amongst our total set of wells. We'll direct our first half efforts in the areas of the field where we have a high degree of confidence in our understanding of the geological, geophysical and reservoir attributes of the field.

We also, during 2013, conducted pilot tests of different methods of artificial lift. Based on what we've learned and our conclusions -- is such that we will -- most of the wells we'll drill in 2014 will be placed on rod pump versus submersible pumps. And we have found that wells placed on rod pumps exhibit shallower declines, more predictable production profile. In addition to that, the savings by going to rod pump versus ESP is about $200,000 per well, which enhances our overall well economics.

During the first half of '14, while we wait for the reprocessed seismic and continue to evaluate well performance data, we've elected to reduce and defer our activity in the Eagle Ford. This will result in a lower production growth profile from the Eagle Ford, but we still believe we will accomplish the same level of growth which we achieved in 2013. We're making substantial progress to continue to reduce our Eagle Ford well cost.

Our wells drilled in 2013 were 15% lower than 2012. Our fourth quarter well costs averaged about $5.6 million per well. We believe in 2014, we will see a continued reduction in well cost to the $5 million and below -- $5 million per well and below as we continue to increase efficiencies, fine-tune our completion design, use a greater number of rod pumps and the start-up of our centralized production facility. Our recent drilling activity in Q1 supports our confidence in our ability to continue to reduce these well costs, and at the same time, improve our well performance.

In the Ark-La-Tex region, our recent drilling activity has focused on high liquids Cotton Valley formation and other oil and liquids-rich horizons within the East Texas region. Recent strength in natural gas prices has created improved rates of return on these projects and has a potential to add significant value to our Ark-La-Tex portfolio, where we have approximately 2,700 locations, about half of which are oil or liquids-rich locations. And we're pleased with our inventory and the team that's working up the prospects in those areas. During the fourth quarter, we completed 1 Cotton Valley well, which had 30-day average gross rate of 8.4 million a day with 35% contribution of liquids. This is consistent with our 2013 program average, which included 6 wells that had 30-day average gross production rates of 8.7 million a day of gas equivalent, 40% of which were liquids.

A modified and enhanced drilling and completion design was implemented in the latter part of 2013, which reduced our average well cost to approximately $7.4 million. This is compared to a previous cost structure of around $8.5 million. We believe we can continue to reduce cost and improve results in the Cotton Valley. And based on this, with the improving price environment, lower drilling costs and excellent well results, we have elected to increase our level of activity and recently added a second operated rig in the Cotton Valley, with a third rig planned for mid-second quarter of 2014.

We have an identified inventory of over 200 locations, which are ready to drill and will provide us with about an 8-year drilling inventory at our current pace. We also have 75 locations in our oil play, which we plan to begin developing -- continue our development in the second half of this year. In addition to that, there is over a thousand dry gas locations in the Arkoma Basin and other locations within the greater Ark-La-Tex region.

We plan to continue the development of our light sweet crude oil play, which I just referenced, where we have completed 3 horizontal producers since initiating this program in the second half of 2012. The 75 locations are on approximately 19,000 gross, 14,000 net acres within a very concentrated area in East Texas. We're currently finalizing our integration of the 3D seismic survey, and we'll begin to increase our level of activity in the second half of 2014 based on the encouraging results from our existing wells and what we see on the 3D seismic. The increased level of activity in East Texas will -- allows us to maintain a nice operational balance and consistent level of drilling activity as we continue to move the Eagle Ford program forward toward the second half of this year.

Thank you, all, and I would like now to turn this call to Victor Wind, our Chief Financial Officer, for his comments.

Victor A. Wind

Thanks, Pat. I'll begin my comments with a short summary of this quarter's activity and then discuss our 2014 outlook, incorporating the changes in our capital allocation plans that Pat just reviewed.

Our fourth quarter reported net sales volumes averaged 165 million cubic feet per day. Excluding the 56 days of production associated with the Texas Panhandle asset that closed on November 25, our net sales volumes averaged 111 per day for the quarter, which was in line with our guidance range of 110 to 115 that we provided last quarter. Although 2013 production had several moving pieces, the asset sales that we completed throughout the year, we continued to make progress transitioning our production volumes to higher liquids weighting.

On a pro forma basis, liquids volumes made up 29% of total production volumes, which is up 10% from 19% in 2012. Oil production increased 55% in 2013 compared to 2012, and our total liquids volumes, including NGLs, increased 41%. A reconciliation of our full year and fourth quarter 2013 pro forma production volumes by quarter and by operating area can be found in the tables on Pages 3 and 8 of our earnings release.

With $66 million of cash on hand at December 31, Forest exited the year with net debt of $734 million compared to $1.6 billion on September 30. The decrease was due to the use of the Texas Panhandle divestiture proceeds in the fourth quarter to redeem $700 million of senior notes outstanding and to pay off all the outstanding borrowings under our credit facility. The $700 million of senior notes redemption was achieved by use of a waterfall tender that allowed us to redeem more than half of our noncallable 7.5% 2020 notes at a lower premium than the premium paid on our callable 7 1/4% 2019 issuance.

Moving on to our updated 2014 guidance. As Pat detailed in his comments, we've elected to reduce the pace of development in the Eagle Ford and redirect capital to the Ark-La-Tex region so we can maintain a fairly consistent level of drilling throughout 2014. Accordingly, our total capital budget remains unchanged at $300 million, at the midpoint of our guidance range, but the drilling and completion component of the capital budget is now allocated 64% to Ark-La-Tex and 36% to Eagle Ford, compared to 23% and 77% previously.

Our forecasted 2014 average equivalent net sales volumes also remains unchanged from the original guidance and is expected in the range of 120 million to 130 million cubic feet per day. Average net sales volumes are estimated to be comprised of approximately 35% oil and natural gas liquids and 65% natural gas. This infers a 10% equivalent sales volume growth and a 30% growth in oil, each on a pro-forma basis.

Incorporating the impact of slightly lower overall drilling pace during the first half of 2014 as we ratcheted up our activity in the Ark-La-Tex and taking into account the lower-than-expected fourth quarter well results that Pat outlined in his remarks, our first quarter net sales volumes are expected to average in the range of 105 to 110 million cubic feet per day. This is expected to be comprised of 67% natural gas and 33% liquids.

Our equivalent net sales volumes are expected to increase on a quarterly basis throughout 2014, although we should see a notable uptick in second half volumes compared to the first half as we benefit from the increased Ark-La-Tex activity. Based on our current projections and planned 2014 activity, our fourth quarter of 2014 net sales volumes are expected to average 145 to 150 million cubic feet per day, which is 37% higher than our projected first quarter volumes, at the midpoint of our guidance.

Carrying the growth trajectory of this program forward into 2015, one could reasonably assume we'd have robust growth in 2015 over '14. Just 2 other quick comments on our guidance. Based on the greater level of activity in the Ark-La-Tex region, our overall production costs including LOE, taxes and transportation will be lower than originally guided, bringing the total company average down to $1.55 to $1.65 per unit. And secondly, our DD&A range should also be slightly lower at $2.45 to $2.65 per unit for the year.

With that summary, I'll hand the call back to the operator for questions. Thank you.

Question-and-Answer Session

Operator

[Operator Instructions] The first question is from the line of Jason Gilbert from Goldman Sachs.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

So how do we think about the inventory of the Eagle Ford locations based on the new information we have here?

Patrick R. McDonald

We think our inventory locations is nearly what we had previously announced to be slightly less based on the spacing that we've identified, depending on the area of the field. I think previously, we were saying something of mid-600s in terms of locations. We're probably closer to the mid-500s now based on our review and analysis of the spacing that we plan to employ during the development phase.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Okay. And we'll know more about that in the third quarter, it sounds like?

Patrick R. McDonald

Well, I think as we continue on through 2014 now and throughout the year, we'll have a much better sense of how the development will take place. But at the moment, our plan is, depending on the area of the field, between 500 to 1,000 foot between laterals.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

And then on your credit facility, the borrowing base was moved down to $400 million in the fourth quarter. Should we expect any further changes to the borrowing base?

Victor A. Wind

We have our meeting scheduled, our semiannual spring lenders meeting scheduled in March. So we'll review that at that time. But we have seen the price deck move down a little bit from previous redetermination. So we'll -- we face a little bit of a headwind there, but we'll know more in March.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

And can you sort of guide us as to what we should be expecting there?

Victor A. Wind

Probably down, I would say, maybe in the $50 million range.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Okay. And then one more before I turn it over to someone else. Can you just update us quickly on any plans for the West Texas acreage? And then maybe is there any notable offset industry activity you should mention?

Patrick R. McDonald

Yes, we're actively seeking partners there. We'd like to get some wells drilled this year, and there are at least 2 locations just offsetting our acreage, currently drilling. So we've been receiving a higher degree of interest here lately in those properties. So we hope to be able to get some wells drilled, maybe participate in horizontal Wolfcamp wells, sometime in the not-too-distant future.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

So that would be -- maybe we'll hear something on that in '14 or is that...

Patrick R. McDonald

Yes, '14, for sure.

Operator

The next question is from the line of David Deckelbaum from KeyBanc. We'll move on to our next one. It's from the line of Sean Sneeden from Oppenheimer.

Sean Sneeden

Could you perhaps talk a little bit about your appetite for acquisitions here? Do you feel -- for instance, is there anything that -- bolt-on acquisitions on your existing acreage, for instance, would you look at some of the packages out there and specifically in East Texas?

Patrick R. McDonald

Well, we're actively acquiring land and looking at, like you say, contiguous or bolt-on-type acquisitions. We're not really looking for any big, large transaction, which most of the marketed transactions seem to be of significant size. So we're focused on developing the acreage that we already have and blocking out our positions both in East Texas and in the Eagle Ford. And we're doing that successfully in both areas.

Sean Sneeden

Okay. Now is there any sort of size that you guys feel is appropriate, something that is currently fundable within your liquidity? Is that sort of a fair way to think about it?

Patrick R. McDonald

Yes, I mean, we're -- I don't know that I can put a dollar amount on it, but given the resources that we have and the size of the company that we are, that kind of sets out the boundaries for us.

Sean Sneeden

Okay. And then just thinking about funding for this year, just looking at your guidance, it looks like you're probably going to outspend cash flow a little bit this year. Can you perhaps just weigh in your mind using your -- using available liquidity versus maybe selling down additional assets or cutting back CapEx? Or any sort of guidance on how you guys think about that would be helpful.

Victor A. Wind

Yes, Sean, we do expect to outspend cash flow in terms of our capital expenditure program. But you've got to keep in mind, a lot of it was pre-funded in the sense that we had about $65 million of cash coming into the year. So in terms of asset sales, we feel like we're pretty well complete with that, after the 2013, $1.3 billion of asset sales.

Sean Sneeden

Okay. And then maybe just on the potential West Texas JV or something like that, would you guys be looking to structure a deal that would be more cash upfront or would you be more in favor of like drill and carry?

Patrick R. McDonald

We like the drill and carry concept. There might be some cash for acreage but our focus is on getting some wells drilled. We like -- the activity is clearly moving in our direction. Good announced well results. And we have 2 very good vertical Wolfcamp wells that have held up nicely and support the idea of a horizontal program. So we don't want to sell it. We'd like to figure out a way to get it drilled, and that's what our focus is.

Sean Sneeden

Makes sense. And then just one housekeeping question. Do you happen to have offhand your PV-10 associated with the Ark-La-Tex region?

Victor A. Wind

Yes, I do. Let me see here. Actually, no, I don't. I apologize for that. That's something we can follow up with and get back to you.

Operator

The next question is from the line of David Deckelbaum from KeyBanc.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

My question is now on -- now with the -- you mentioned in the press release you want to hold 49,000 gross acres now. What sort of pace does that assume? Are you going to get back to sort of a 3- to 4-rig program towards the end of the year in the Eagle Ford? Can you elaborate a little bit on that?

Patrick R. McDonald

That is a possibility. Much of that depends on our early 2014 well results and getting through this interpretation and integration and merging of our 3D seismic survey.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Okay. And outside of, I guess, this 6,000 or so acres that are adjusted from the original plan, as you observe sort of the well results now, do you still feel confident in sort of an average-type curve of 300,000 barrel equivalent?

Patrick R. McDonald

We're going to bring that type curve down. And our pods at year end were booked at 240 -- 239,000 barrels of oil versus -- the apples and apples comparison would be about 270,000 barrels of oil on the 300 BOE. So we're bringing that down to -- by 30,000 barrels of oil.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Okay. And my last question just on the Permian side. You said you're seeing some vertical activity, and we have seen, I guess, an increase in offset operator activity there, and you said that you want to find a partner. I mean, is there a timeline that you would look for a partner? And if you don't find that partner, is there going to be a point where you start to look to shift the activity over there or do you feel like there's still a decent amount of delineation risk that exist for your acreage out there?

Patrick R. McDonald

Thank you. Just to clarify, we, Forest, have 2 vertical wells. There are horizontal wells being drilled offsetting our acreage. And so then the second part of this is we are in discussions with people that have expressed an interest in this drill and carry concept. So it's something that we plan to accomplish soon -- sooner rather than later. The question is to whether or not we would pull capital away to invest there. I think that will depend on taking it cautiously and watching some of the offset well results and hoping to get some wells drilled here in 2014 before we make a decision to reallocate capital from some of our other properties. I would say that it's still an early-stage development. We're clearly not in the center of the activity. So we're going to make sure we do this prudently.

Operator

The next question is from the line of Paul Grigel from Macquarie.

Paul Grigel - Macquarie Research

On the 14,000 net acre position in East Texas, you mentioned you've drilled 3 wells since the second half of 2012. Would it be possible to go into what those results broadly look like in terms of production levels and production mix?

Patrick R. McDonald

Yes. Our type curve there is about a $4 million well, 150,000 to 175,000 barrels of oil. And that puts rate of return in kind of the mid-30s based on strip pricing.

Paul Grigel - Macquarie Research

And is there -- in terms of a component of how much is oil, is it 75%, higher or lower than that?

Victor A. Wind

Yes. It's actually 70% oil, 10% NGLs and 20% gas. Just one other follow-up question for Sean at Oppenheimer, the PV-10 of the Ark-La-Tex region is about 475 million.

Operator

We have no further questions in the queue at the moment. I'll hand the call back to you to conclude.

Patrick R. McDonald

Okay. This concludes our call for today. I want to thank everyone for joining us. If you have any further questions, feel free to contact us. Thanks.

Operator

Thank you. Ladies and gentlemen, that concludes your call for today. Thank you for joining. You may now disconnect.

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