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Forest Oil (NYSE:FST)

Q1 2013 Earnings Call

May 07, 2013 9:00 am ET

Executives

Larry C. Busnardo - Director of Investor Relations

Michael N. Kennedy - Chief Financial Officer and Executive Vice President

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

Analysts

Scott Hanold - RBC Capital Markets, LLC, Research Division

Trevor Seelye - Wells Fargo Securities, LLC, Research Division

Dan McSpirit - BMO Capital Markets U.S.

Dan McSpirit - BMO Capital Markets Canada

Stephen Shepherd

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Q1 2013 Forest Oil Corporation Earnings Conference Call. My name is Cathy, and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes.

I would like to turn the call over to Mr. Larry Busnardo, Director, Investor Relations. Please proceed, sir.

Larry C. Busnardo

Thank you, Catherine, and good morning. Thank you for joining us for the Forest Oil First Quarter 2013 Earnings Conference Call. Joining me on the call today is Patrick McDonald, Forest President and CEO; and Michael Kennedy, Executive Vice President and Chief Financial Officer. If you have not already done so, please go to our website, forestoil.com, to obtain a copy of our earnings release. A replay of this call will be available through May 21 as described in our press 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 now turn the call over to Mike.

Michael N. Kennedy

Thanks, Larry, and good morning, everyone. Pat will provide an operational update in his prepared remarks. So I'll start out with a summary of the financial highlights for the first quarter.

The first order of business for the first quarter of 2013 was the closing of our previously announced South Texas asset divestiture on February 15. At closing, Forest received net cash proceeds of $307 million, after closing adjustments and a hold back of $14 million for certain properties that the required assignments have not been received prior to closing. Since the end of the quarter, Forest has received the remaining $14 million of additional proceeds. The proceeds from the sale were used to redeem the remaining $300 million 8 1/2% senior notes that were due in 2014. Forest paid a $21 million call premium in conjunction with the early redemption of the notes.

I would highlight that with this transaction, we now completed over $600 million of asset sales since the middle of 2012, with all the proceeds being used to pay down debt. In connection with the closing of this transaction, the global borrowing base under Forest's credit facilities was reduced to $900 million. And earlier this month, our lenders reaffirmed the borrowing base at $900 million as part of their regularly scheduled semi-annual redetermination.

Now turning to production. We reported first quarter equivalent net sales volumes of 243 million per day. When stripping out half a quarter of production associated with the South Texas asset divestiture, our pro forma sales volumes came in at 214 million per day, of which 37% were liquids.

Our pro forma oil volumes for the quarter were approximately 5,800 barrels per day. The lower sequential oil volumes were primarily the result of the timing of oil well completions in both the Eagle Ford Shale and in the Texas Panhandle, and the impact that weather had on our operations in both the Texas Panhandle and the East Texas area.

Specifically, the 6 gross or 3 net wells that were drilled in the Eagle Ford Shale did not contribute to first quarter volumes as they did not come online until April. We should begin to see a more gradual increase in oil volumes throughout the year as the Eagle Ford drilling program increases. We are currently forecasting second quarter equivalent net sales volumes to be at approximately the same levels they were in the first quarter on a pro forma basis with natural gas volumes lower and oil volumes higher. This incorporates the impact of the recently announced Eagle Ford Shale development agreement. However, our continued focus on oil opportunities will allow oil volumes to begin to overtake the declines in our natural gas production, and we should see a steady uptick in our oil volumes and our total volumes during the second half of the year as our activity increases.

I'd now like to spend a moment on our first quarter capital spending. Capital expenditures for the quarter were approximately $125 million. The first quarter was anticipated to be the highest quarter related to this year's spending. This is primarily due to the timing and sequence of drilling and completion operations associated with the pad drilling in the Eagle Ford Shale. And we added a second rig in the quarter in anticipation of the Eagle Ford Shale development agreement.

For the remainder of 2013, we project that our net capital expenditures for each quarter will be between $70 million and $80 million, despite having an increased level of net activity. This is due to the benefit of the Eagle Ford Shale development carry, which started on April 11, and that we'll be receiving into 2014. Importantly, the accelerated development plan in the Eagle Ford will allow us to drill 10 additional net wells this year, but the cost of these wells will be offset by the drilling carry, keeping us within our guidance range of $355 million to $375 million for the full year.

We had a good quarter on the expense side of the equation as we came in at the low end -- or below the low end of our guidance for all of our cost metrics. Apart from the production and capital cost guidance for the second quarter of 2013, the remainder of our guidance that was provided in February remains unchanged.

With that recap, I will now turn the call over to Pat for his comments.

Patrick R. McDonald

Thanks, Mike, and good morning, everyone. Thanks for joining the call.

During the first quarter, we made additional progress in achieving our goal of accelerating the development of our large opportunity set with a focus on the oil projects within our inventory. We continued to execute on the strategy that we outlined almost 1 year ago now. And as we go forward, we continue to develop the oil opportunities in our 3 principal areas. Our focus on return to growth is enhanced by the transaction that we engaged in on the Eagle Ford Shale, and we look forward to increasing production and cash flows as a result of that program throughout 2013 and into 2014.

During the first quarter, we continued an active development program and will soon have the 6 rigs at work, 3 in the Eagle Ford Shale, 2 in the Texas Panhandle and 1 in East Texas. We plan to maintain this level of activity in the Panhandle and East Texas throughout the year. We will also add a fourth rig to the Eagle Ford program in the coming months as we ramp up the drilling program on the acres in Gonzales County. We continue to hold significant development opportunities within the oil zones -- oil-bearing zones of the Texas Panhandle, and we'll continue to focus primarily in Texas Panhandle but also on some of the acreage that we hold in the Oklahoma side. We maintain a large inventory of over 500 identified locations within the Hogshooter, Tonkawa, Douglas and other proven oil horizons, and we look forward to continuing the development of this asset base as we move forward.

The current focus is in Wheeler County, Texas, where we have identified 100 or so potential Hogshooter opportunities and locations. Maintaining the focus in this area will allow us to capture the economies of scale as we look forward to lowering our drilling and completion costs, as well as operations through more efficient focused operations.

In the first quarter, we participated in the drilling of 2 Hogshooter wells that had average 30-day gross production rates of 1,800 barrels a day. These results are consistent with what we are seeing across our position within our broader program.

The infrastructure additions in the Panhandle remain on track as we anticipated with Forest recently moving gas volumes on the Southern Hills pipeline. This will allow us to move our NGL volumes to distribution facilities and pricing points at Mont Belvieu, Texas. This is an important product outlet for Forest as it provides increased transportation options and access to what has historically been a better pricing environment compared to Conway. The Texas Panhandle will remain an area of emphasis for Forest and we will maintain a 2-rig development program throughout 2013, entirely focused on oil drilling to capture the value that resides within this asset base.

In regard to the Eagle Ford Shale, we will continue to evaluate our opportunities to accelerate the development and the holding of our acreage position in the Eagle Ford Shale. Our joint venture partnership with one of the industry's leading science and technology company will allow us to enhance and create efficiencies in all facets of our drilling and completion operations, as well as ongoing operating expense reductions. We believe that this program will allow us to hold the entire 55,000 acres that we now consider to be the core area. It allows for an accelerated development program resulting in oil production growth and improved economics as we apply the technologies that we hope to -- from which we hope to benefit as we go forward with our partner. We believe this will enhance the capital efficiency of the program, better well results, more robust economics and higher ultimate recoveries and well productivity.

The $90 million of drilling carry combined with the accelerated program brings forward approximately $250 million worth of present value economics to Forest. The accelerated plan is the result of the program results in 10 additional wells in 2013 and 20 additional wells in 2014 compared to our previous program. We believe that the 2013 wells will be on production later in this year, most likely Q4, and do not anticipate that they will materially change our average net sales volume for 2013. However, we believe that the full benefit of the ramped up program will kick in during 2014 and we hope to increase our daily net -- our gross production to 6,500 barrels a day, I'm sorry, net production, 6,500 barrels a day. That's an increase from an average of 1,600 barrels a day net in 2012. So a significant increase in oil production is projected.

The increase in the capital as a result of the increase in the number of planned wells will be covered by our drilling carry. So our total capital expenditures will remain unchanged. We believe that we have the appropriate confidence in our technical and operating personnel to take -- to handle this level of drilling to further increase the level of activity. And so far, we're able to realize the benefit of the increased drilling activity without any hiccup in operations.

Our net sales volume from the Eagle Ford Shale averaged 1,900 barrels a day in the first quarter of 2013 compared to fourth quarter 2012 volumes of 2,300 barrels a day. This anticipated decline was due to the timing of bringing on the pad drilling during the fourth quarter of 2012 and the first quarter of 2013. The 6 wells that were drilled during the first quarter came on at various times during April. While the wells do not have sufficient production history to report 30-day or 60-day average production rates, the initial rates from these wells was over 600 barrels a day, and we believe they're at or exceeding our expectations for the program.

We recently hit a high sales volume in April of 4,700 barrels a day of gross production volumes, and that is the record for the Eagle Ford -- for Forest in the Eagle Ford.

We'll have a third rig moving in this week to begin drilling and a fourth rig in the next couple of months. So by the late third quarter, early fourth quarter, we should have our full rig program at work. And as we continue to focus on efforts on lowering costs, we've entered into a third-party gathering, treating and processing agreement that will provide central facility gathering and transportation, gas processing and water handling for the Eagle Ford Shale production. We expect this capital investment on -- in the midstream asset to be online late fourth quarter, early first quarter of 2014.

We'll continue to streamline our operations and provide cost efficiencies and cost savings for as we increase the level of activity in the Eagle Ford Shale.

That completes my prepared remarks. And we'd be happy to answer any questions that those of you on the call may have. Thank you. Operator?

Question-and-Answer Session

Operator

[Operator Instructions]. And please standby for your first question, which is from the line of Scott Hanold from RBC.

Scott Hanold - RBC Capital Markets, LLC, Research Division

When you step back and take a look at the activity, you guys are running a well in East Texas, can you give a sense of right now what the returns are looking like on that activity, and when you look at the alternative, say, of more debt reduction versus drilling in that play, or maybe even another rig in the Panhandle or the Eagle Ford play, what is sort of the trade off of East Texas versus some of those other options?

Patrick R. McDonald

We like the predictability and consistency of our results in East Texas. We're also actively developing an oil project in East Texas that we haven't talked about publicly. So we're actually pretty high on our possibilities there as we go forward. We all -- but we do like the balance between the 2 rigs in the Panhandle and the third rig in East Texas. We view them as somewhat interchangeable from an economics point of view. But at the moment, [indiscernible], the Hogshooter locations have superior economics to the East Texas opportunities, so we'll -- we plan to stick with our 2 rig in the Panhandle, 1 rig in East Texas program for the moment.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. Now you whet my appetite here. You have an oil concept in East Texas, is this similar to, say, what Anadarko is doing in there in the Haynesville or is this a different type of concept?

Patrick R. McDonald

I can't speak to what Anadarko is doing, I don't know, but we -- I think we'll just leave it at that, that we have an oil play and we like it so far. We've drilled some wells and are pleased with our position and...

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. Is this off your legacy East Texas asset base that it's --

Patrick R. McDonald

Yes, yes. We have fairly sizable position in these plays.

Scott Hanold - RBC Capital Markets, LLC, Research Division

And this is not a Cotton Valley concept, this is something a little bit different?

Patrick R. McDonald

It's not Cotton Valley.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. I'll leave at that, fair enough. And just one quick question for maybe for Mike. Severance taxes were pretty loaded in the quarter, was there a rebate there that drilled that down? And what is sort of the expectation on the go-forward quarters?

Michael N. Kennedy

Yes, there was a rebate from the State of Texas. Go forward, I think that's contributed somewhat to our $1.18, I believe, all in LOE, versus our guidance of $1.30 to $1.35. We're leaving the $1.30 to $1.35 in place, so we'll be slightly higher in the coming quarters, but we did enjoy that in the first quarter.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. So should we use like a 4.5% to 5% severance percent of pretax revenue?

Michael N. Kennedy

Yes, that's about right.

Operator

The next question is from the line of Trevor Seelye from Wells Fargo.

Trevor Seelye - Wells Fargo Securities, LLC, Research Division

Just a couple of quick ones. In the Mid-Continent, so the Hogshooter and Wheeler County, one of your competitors said that the wells weren't living up to expectations out there. Can you just address that from your viewpoint, maybe what you guys are doing differently and why you're seeing better results?

Patrick R. McDonald

Yes, I don't know that we're doing anything differently. We're pretty happy with our prospects there, and our program for the next couple of quarters is already well mapped out.

Michael N. Kennedy

Yes, and Trevor, we've already said our EURs are between 350,000 and 500,000 barrels, and we've definitely been hitting in that range. I don't know if others had higher expectations.

Trevor Seelye - Wells Fargo Securities, LLC, Research Division

Okay, that's fair enough. And then standing in the Panhandle, you guys have talked about picking up a partner out there. Are you formally marketing that or at this point, just fielding inquiries?

Patrick R. McDonald

No, there's no formal process.

Trevor Seelye - Wells Fargo Securities, LLC, Research Division

Okay. And then just last one in the Eagle Ford. Now you guys have had some time with Schlumberger, is there anything that they have in mind to do differently on the well design?

Patrick R. McDonald

There are numerous initiatives to enhance the productivity and to reduce the cost. So yes, we're -- there's active ongoing interaction between the 2 companies. The 2 technical teams that have been posted to the project meet regularly. And so far, there have been some very good ideas. We haven't implemented any of the changes yet but we plan to here on the next round of drilling.

Operator

The next question is from the line of Dan McSpirit from BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

Can you speak to the decline rate on the underlying gas assets, what is it today? What was it say, 6, 12 months ago? And what does it look like, say, 6 months from now? Just trying to get a sense on how the shape of that curve changes as later vintage wells roll off?

Michael N. Kennedy

Yes, that's a good question. And Dan, we're right now between 30% and 35%. That gradually declines to about next year it's in the low 20% because you won't have any of the wedge or the newer production on.

Dan McSpirit - BMO Capital Markets Canada

Got it, that's helpful. And then as a follow-up, what do you see leverage say, at the end of this year and year-end 2014? Maybe answer it without proceeds from any contemplated asset monetizations that could go to pay down debt.

Michael N. Kennedy

Yes. Right now, with the $70 million to $80 million of capital and our cash flow where we put it, probably $60 million to $70 million, you're just going to have minimal increase in net debt from where we're at right now. When you combine that with the accelerated development from the Eagle Ford program and additional EBITDA that that's going to throw off, your leverage stats probably peaked this quarter or probably flat next year. And then from then on, they'll start to improve. So about the same amount of net debt with additional EBITDA.

Dan McSpirit - BMO Capital Markets Canada

Perfect. And how do the 500 locations identified in the Texas Panhandle break down? That is, how much Hogshooter, Tonkawa, Douglas and other? I think you had mentioned something about 100 Hogshooter locations.

Patrick R. McDonald

Yes, we have that in our corporate presentation, dishing that out, I think, yes, it's on the website...

Michael N. Kennedy

On Page 11.

Patrick R. McDonald

Yes. I think we're showing of that 500, about, call it 1/3 or -- no, about -- Missourian Wash are maybe half of that, and then the other oil zones, it's a mix to provide the other half of the 500.

Dan McSpirit - BMO Capital Markets U.S.

Okay, great. And then last one here. To clarify, the 55,000 net acres you identify as is core in South Texas for the Eagle Ford Shale play, is that net to your interest after considering the 50-50 partnership with Schlumberger?

Patrick R. McDonald

No, sir, that's the gross number.

Operator

The next question comes from the line of Stephen Shepard from Simmons.

Stephen Shepherd

So with the increase in gas prices we've seen, what price point would you look at putting a rig back to work in the Louisiana, Haynesville?

Patrick R. McDonald

I think, for us, we might start to approach some single-well economic hurdle rates that make it attractive. But we can't pull capital away from our oil drilling, which still -- even at pick a number on the Nymex, it still -- the economics of the oil drilling still exceeds those economics on gas drilling.

Stephen Shepherd

Okay. And then one more, if I can. How is the Permian divestiture proceeding? Is there any offset operator drilling which is enhancing the value of that acreage or helping there? Just looking for some comments on that.

Patrick R. McDonald

Yes, there is a fair amount of offset activity, not exactly right in the neighborhood of Forest acreage. But we feel that any activity, especially with good results as published, helps our position, generates additional interest in the Forest acreage position.

Operator

The next question is from the line of Jeoffrey Lambujon from Tudor, Pickering, Holt & Co.

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

On your Q1 volumes, would you be able to give some additional color on the weather impact on your East Texas and Texas Panhandle? Maybe how long ops were negatively impacted by how much and if there's a residual impact going forward into Q2?

Michael N. Kennedy

Yes, there is no residual impact. The actual impact for the quarter was 4 million to 5 million a day.

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, great. And just one more, going onto Q2 volumes. The 214 million cubic feet equivalent per day number pro forma of the South Texas divestiture, just to clarify, these are coming around the same volume with production weighted towards the back half of the year, correct?

Michael N. Kennedy

Correct.

Operator

The next question comes from the line of Jason Gilbert from Golden Sachs.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Just sort of kind of a housekeeping question, but on my numbers, it looks like you may be bumping up against the leverage covenant on your bank facility coming mid year, am I off there? And if I'm not off, what are you doing to address that?

Michael N. Kennedy

No, I think you are off. Not bumping up, our forecast as I said -- the credit facility calculation, as I said peaking this quarter and next at 4.3 -- 4.3x. Then it obviously starts to go down with the contribution from the Eagle Ford oil volumes and the acceleration of the growth from that transaction.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Okay. I may follow up with you off-line in some of our math.

Operator

[Operator Instructions] The next question is from Jonathan Reiley [ph] from Longbow Capital.

Unknown Analyst

Kind of a follow-up on that last question. When you look at your '14 EBITDA consensus, $455 million, it's clear you're getting analyst recognition for some of the success related to the Schlumberger Eagle Ford JV. However, it really seems in order to attract new investors with the stock where it is, you need to do something more aggressive on the debt burden. I guess a 2-part question. One, do you think you realistically have the assets to monetize to address the debt load in a more dramatic fashion?

Michael N. Kennedy

Yes, we do have the assets.

Unknown Analyst

And just, two, do you think at this point management, given the share price, and the board are willing to take more dramatic steps to reduce debt?

Michael N. Kennedy

I think we're looking at that. The first step back in mid last year, we said, was to improve the balance sheet, we've done that $600 million of asset sales and using that to redeem 8 1/2s. The second step is to try to get the accelerated development on our assets and really delever through the EBITDA part of the equation. And obviously, we did a tremendous first step with the Schlumberger deal, so we'll continue to look at those type of opportunities.

Unknown Analyst

Can you just remind us, how much of your facility is tied to East Texas?

Michael N. Kennedy

I don't know the exact number. I mean, I would guess it's probably 1/3.

Unknown Analyst

1/3. And roughly how much production is coming out of East Texas currently?

Michael N. Kennedy

Approximately 100 million a day.

Operator

The next question is from the line of [indiscernible], Nomura.

Unknown Analyst

Two questions, just to follow up on the Eagle Ford. One was, could you discuss, I mean, what you're seeing in terms of well cost now that you're drilling with pad drilling in the Eagle Ford? And also, I think it was the last quarter or the quarter before that you guys mentioned that you were testing a restricted choke pilot, and if there was any -- if there were any wells drilled with that or if there was any kind of results from that.

Patrick R. McDonald

I think, we've been able to bring our well cost down from single-well costs in the $7 million range down to low $6 millions, and we're trying to push it down below $6 million through the pad drilling effort. I'm not sure if I understand the question about the restricted rate. We had a little bit of experimentation on rod pumps versus ESPs, and now we've gone to submersible pumps exclusively. So we're producing the wells full out. We believe the highest rate of return is from moving the most amount of fluid as fast as possible, and that's the focus of our program.

Unknown Analyst

That's fine, I'll follow-up offline. I thought I had read in one of your previous releases, so I'll follow-up.

Operator

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

Larry C. Busnardo

Okay. This concludes our conference call. Thanks again for joining us this morning. If you have any further questions, please feel free to contact us. Thank you.

Operator

Thank you for joining in today's conference. This concludes the presentation. You may now disconnect, and have a very good day.

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