SandRidge Energy Inc (SD) 2014 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the SandRidge Energy's fourth-quarter 2014 conference call.

(Operator Instructions)

Please note, that this call is being recorded today, Friday, February 27, 2015, at 9 AM Eastern Time. I would now like to turn the call over to Mr. Duane Grubert, EVP of Investor Relations and Strategy. Mr. Grubert, you may begin.

Thank you, operator. Welcome, everyone, and thank you for joining us on our conference call. This is Duane Grubert, EVP of Investor Relations and Strategy here at Sandridge. With me today are James Bennett, President and Chief Executive Officer; and Eddie LeBlanc, Executive Vice President and Chief Financial Officer.

We would like to remind you that in conjunction with our earnings release and conference call, we have posted slides on our website under Investor Relations that we'll be referencing during the call. Keep in mind that today's call contains forward-looking statements and assumptions which are subject to risks and uncertainties. And actual results may differ materially from those projected in these forward-looking statements.

Additionally, we will make reference to adjusted net income, adjusted EBITDA and other non-GAAP financial measures. A reconciliation of the discussion of those measures can be found on our website. And please note that the call is intended to discuss Sandridge Energy, and not our public royalty trust. Now let me turn the call over to CEO James Bennett.

Thank you, Duane. Good morning, everyone. Welcome to our fourth-quarter 2014 call. As we move on beyond the volatile 2014, we're all living in a price environment that is markedly changed since we last spoke. My goal today is to leave you with a clear vision of how we responded to this change in oil price with a heightened level of capital discipline, leveraging our ongoing asset performance, managing our liquidity, and a focus on right-sizing our balance sheet. All of our tactics result in a plan for us to be successful in an environment with oil and gas prices in the $50 and $3 range.

Today we'll introduce our 2015 capital planning guidance, new well cost targets, talk about our oil-gas mix, our new type curve and reserve report. We'll also give details on covenant changes designed to provide flexibility, and our thoughts on addressing our debt levels and cash flow.

First, I will highlight a few of our successes from 2014, but focus most of my time on how we position the Company for 2015 and 2016 as we manage the business in this lower-price environment. Along with our earnings, we posted a slide deck. I'll use some slides to complement the discussion today. On page 3, you'll see a summary of our high-level themes for 2015.

Our ongoing success is evidenced by hitting our 2014 growth guidance and materially adding reserves. Reserves are up 37%, with our Mississippian PUD type curve up 27% to 484,000 barrels of oil equivalent. Supported by over 1,300 wells and signaled by several quarters of greater-than-type curve IP rates and cumes. Fourth-quarter Mid-continent production grew 47% versus a fourth quarter of 2013 to 76,000 BOE per day. And Company production for the year came in 1% over guidance, at 29 million barrels of oil equivalent.

From this proven ability to execute, we want to highlight our improved capital efficiency. Compared to a 2014 total program well cost of $3 million per lateral, we are quickly moving towards a $2.4 million per-lateral well cost for the back-half of 2015, which I will give greater detail about in a moment. These new costs and our improved type curve combined to make us competitively capital-efficient, even in this price environment.

On liquidity and leverage, in February, we were proactive and took an early opportunity to amend our leverage covenant to ensure plenty of flexibility into 2016. We also determined our borrowing base and maintained our $900 billion availability. Recall that at year-end, we had over $180 million cash, and approximately $900 million available under our borrowing base.

In the appendix of the slides and in our earnings release, we outline our capital plan and detailed guidance for 2015. We set our capital budget at $700 million, which is approximately 60% below our 2014 capital spend. And our guided midpoint yields 6% production growth year over year. It's important to note that 40% of this $700 million CapEx will be spent in the first quarter of 2015, as we ramp down from 31 rigs in December to 19 rigs now, and 7 planned by mid-2015. With that ramp-down, we have over $125 million of rollover CapEx from 2014 drilling and infrastructure projects still in process in Q1.

Turning to page 4 of the slides, we lay out the crux of our improving capital efficiency. To summarize, our 27% higher EUR for 80% of prior costs preserves the returns we had at higher oil prices. The 2014 PUD type curve at our $2.4 million targeted lower costs gives us a 45% return at strip pricing. In-line, our -- better than our prior returns at $80 oil and $3 million well costs.

As we'll discuss, those lower costs are not just a product of service cost reductions, but even more so, real operational efficiencies. Most of these are durable at any price environment, and including a higher emphasis on multilaterals. We know now that our multilaterals produce 100% of the 90-day cume type curve, or just 85% of the cost of single lateral. So with our type curve increasing, costs coming down, plus the advantages of multilaterals, we were able to maintain returns and a very long runway of locations.

On page 5, we outline the guiding principles of our 2015 budget. First, we are only selecting projects that meet our hurdle rates of return at current commodity prices, excluding the value of our hedges. We are not interested in activity-based spending or spending the whole leases. All projects must generate a fully loaded rate of return, including infrastructure costs.

CapEx is being reduced in all areas, to a total of $700 million, as we quickly ramp-down our drilling activity. We would need to see a substantial improvement in prices before we envision a material change in our capital planning. And also may tighten up our spend further if there's additional downward movement in the market.

I am very pleased with our reserve performance and message. Take a look at page 6 of the presentation slides. Recall that in 2014 we tightened up development efforts to concentrate in areas of play where we have the best results and can generate higher returns. Through this focused effort, we've been very successful growing our proved reserves this year, adding 143 million barrels of oil equivalent through the drill bit. Resulting in a 600% reserve replacement on production of 27.6 million barrels of oil equivalent, all pro forma for the Gulf of Mexico divestiture.

This addition increased our proved reserve base 37% to 516 million barrels of oil equivalent. We accomplished these additions for a very attractive all-in finding and development cost of $9 per BOE.

At SEC pricing, PV-10 grew 34% to $5.5 billion. I recognize year-end SEC pricing is indicative of the current market. We calculated PV-10 based on recent strip prices, which averaged approximately $64 and $3.50 over the next five years -- and that proved-only PV-10 at the strip is $3.3 billion.

Next, on page 7 of the slides, we have the detail of our 2014 type curve. As messaged fully throughout the year, we have achieved continued out-performance of 30-day IP oil and gas rates, along with improving 180-day cumes. With this, we are seeing an uptick in our Mississippian type curve to 484,000 barrels of oil equivalent, a 27% improvement versus the 2013 type curve of 380,000. This increase is attributed to higher gas and NGLs. Oil EUR for the type curve remained unchanged at 118,000 barrels of oil. But we did see an 8% increase in oil IP, and a 14% increase in the gas IP, that contributed to improved value in IRR.

Turning to costs, on page 8, we outline in more detail the sources of our cost-reduction efforts. And I want to discuss the rigor that is going into that cost-reduction program. Immediately after the new year, we start a process to look at every category of well-cost spend and find ways to further reduce our costs. We appointed an internal cost manager; his purpose is to ensure we are pressing all corners of our CapEx for cost reductions.

Through the process, we identified three main areas and laid out detailed goals and timelines for each. These savings will come from three identified areas -- durable efficiency gains in operational improvements, reduction in pricing by service providers, and an increased use of multilaterals. Importantly, many of these cost reductions are anticipated to be long-lasting changes to our program and process that will ultimately extend the commercial footprint of the play.

First, operational improvements. This represents 45% of the total identified savings. These are durable process improvements, such as using the most efficient rigs in our fleet to reduce cycle in trouble time, changes to completion methods and wellbore design, location hydrating, increased use of skid pads and co-mingled tank batteries. These efficiencies will continue to enhance return, no matter what future price environment we operate in.

The second, improve pricing, will account for about 40% of the total. This is coming from several areas, including lower stimulation and artificial lift costs, and reductions in drilling rig and directional day rates.

Third, multilaterals and long laterals will comprise the balance of the 15% of the savings. We're going from 20% multilaterals in the back-half 2014, to 40% in 2015. I'll give you more details on our multilaterals in a few minutes.

Combining our cost reduction, process efficiency, and expanded multilateral program, we expect Mississippian per-lateral cost to be $2.4 million in the back-half of 2015. a 20% decrease from the 2014 program. We are committed to this level of cost reduction. And at the end of February, based on process changes and executed new service prices, we have already realized savings of 250,000 per lateral of that targeted $600,000 savings.

On page 9, we illustrate the returns at various prices. It's a combination of our improved IPs and higher type curve, and the lower $2.4 million well cost that I just reviewed, that yields these returns. 27% more EUR for 80% of the cost. As shown on the graph, we can generate 45% returns at strip prices, and even a 30% return at flat $50 oil and $3.50 gas.

Turning to our multilaterals, as shown on page 10. Recall the multilaterals of development approach -- we began testing in 2013, drilled our first well in Kansas in late 2013, and in mid-2014, started using this as a real tool in our development program. The original thesis was -- how can we develop a greater area, or even a full section, for lower costs?

Our teams innovated and delivered on this. And through the success with dual laterals, accessing the same zone -- stacked laterals, accessing two stacked zones -- and now we have proven full-section development, as illustrated on a picture on page 10. As an example of our full-section development success, our Kirkpatrick Farm well, in the third quarter of last year. This well came in at $9.2 million or $2.3 million per lateral, which saved us $2.8 million, compared to spending $12 million to drill four conventional single laterals in a section.

This is a type of well that gives us enthusiasm for expanding our use of multilaterals. For the 2014 program, based on just under 30 multilaterals drilled, we now know that our multilaterals produce 100% of the 90-day cume production of our new type curve, or 85% of the cost of single laterals. Or $2.6 million per lateral. These costs per lateral will continue to come down into the low $2 million range, commensurate with our cost-reduction efforts.

Continuing on this innovation theme, our teams drilled our first long lateral in the Mississippian, in Alfalfa County, Oklahoma. This well had 9,000 feet of stimulated lateral, over two times our standard lateral length. Total costs are estimated at $5.2 million, and the production results and returns look excellent. As a result, we plan to complement our multilateral program and drill additional long laterals in the Mississippian in 2015.

Turning to our drilling program and guidance. The $400 million of D&C portion of our budget, of which approximately $300 million represents new 2015 activity, focuses on high-graded locations in close proximity to existing infrastructure. One of the missed development challenges historically had been the variability across the play. Now, with over 1,400 horizontal wells in our dataset, and 2,200 square-miles of 3D seismic in-house, we have built a technical understanding of that variability, and have been able to continue to improve our performance.

Turn to slide 11 for a map of where our rig activity will be focused. We continue to see very consistent results in Garfield County, Oklahoma. And are confident in the performance in Alfalfa County, Oklahoma, where wells perform at the [up brand] of the distribution. We will also be active with one rig in each southern Harper County, Kansas, and Woods County, Oklahoma.

These will be our primary targeted areas as we high-grade drilling locations. These areas also provide the most ready access to existing infrastructure. So we've been able to cut back that portion of our budget associated with new-well infrastructure. We will continue to have one rig drilling for our appraisal program. This is the same successful program and that found our Chester and Woodford in 2013 and 2014.

Next I'd like to highlight our oil and gas splits in 2015 guidance, illustrated on page 14. The year's capital program is funded at a level that has oil production versus 2014 slightly down at the midpoint, while gas volumes are up 11%, and NGL is up 20% at the mid-point. Recall that we are not targeting a growth rate for 2015; rather, drilling projects that generate a burdened rate of return at the strip.

Decline in Permian oil production is the most influential factor in this small drop in oil volumes year over year. We have no capital allocated for Permian drilling in our 2015 budget, and expect to see around a 30% decline in oil production there, or 500,000 barrels.

For the Mississippian, we're predicting a slight 200,000-barrel decline in oil. This decline is a function of both the type curve profile, where we have higher declines in oil and gas, and the changing mix of wells we added in 2015 versus 2014. So yes, we're growing gas more than oil, at volumes higher than our prior type curve results. And are fine with that outcome, since cash flows and returns don't care what the hydrocarbon mix is.

Turning to page 12, in terms of our balance sheet and overall leverage, we recognize that at current prices, our $3.2 billion debt is high compared to our asset base. We are tackling this from several different angles. First, we have time. Our balance sheet is structured with no bond maturities until 2020. We amended our bank covenants to replace the total leverage ratio, just reaffirmed our borrowing base facility, and at year-end, had over $1 billion of liquidity.

Second, we are reducing our spending and capital levels through our decreased capital program, decreasing it by $900 million, reducing well costs by 20% -- which will drive improved capital efficiency -- and are reducing our G&A expenses. These will improve the cash generation ability of our assets and extend our liquidity runway.

We do have a free cash flow deficit this year. While we have shrunk that deficit every year for the last three years, in this price environment, we need to reduce it further and get closer to operating within cash flow. In 2015, we plan to raise at least $200 million from non-E&P and non-core asset sales and monetization. These will supplement our liquidity and fund a large portion of the spending gap this year.

Finally, just like us being proactive on the borrowing base amendment, we are proactively investigating multiple scenarios regarding ways to right-size the balance sheet in a protracted pricing downturn. We are working on this, and don't plan to sit and wait for prices to recover.

Our plan for 2015, we further strengthened by the hedges we've layered in it at very attractive values. On page 16 and in our earnings release, we outline the details of our hedging. With our reduced CapEx plan, we have 100% of our oil production hedged, and 90% of our total liquids production hedged. Of our 10.2 million barrels of oil hedges, about 5.5 million of those are true swaps at just over $92 a barrel. And the remaining 4.6 million barrels are three-way callers. So as an example, at $50 flat oil, taking into account weighting of the swaps and three-way callers, our effective WTI price would be about $81.50 per barrel for the full year.

In conclusion, while the operating environment is certainly a challenge, our combination of process efficiencies, cost relief, and innovation with multilaterals and long laterals, plus the demonstrated higher type curve EURs, has our 2015 program quite competitive. This enhanced and durable improvement to capital efficiency, with a backdrop of increased financial flexibility from our new borrowing covenants and existing hedges, sets us up defensively for the current environment.

Finally, I like to thank our talented team of employees, who do all the real work, and in a safe manner. Our 2014 performance was excellent, and sets us up for ongoing successful forward -- and you all are the ones that executed this program. That concludes my remarks. Let me turn it over to our CFO, Eddie LeBlanc.

Thanks, James. Today I will cover key financial information for 2014, describe our amendment to the credit facility and review our 2015 guidance. When discussing EBITDA and production, I am referring to pro forma amounts that are adjusted for the sale of the Gulf properties in 2014, and the sale of the Gulf and Permian properties in 2013.

EBITDA for the fourth quarter of 2014 was $224 million, an 18% increase from the fourth quarter of 2013. EBITDA for the full-year 2014 was $820 million, a 35% increase over 2013. For full-year 2014, earnings increase was driven by a 23% increase in year-over-year production. We closed 2014 with $181 million of cash, and an availability of approximately $900 million under our reserve base credit facility.

Additionally, our hedge position at year-end was valued at $338 million. Our senior debt outstanding remained at $3.2 billion. And our covenant leverage ratio was 3.8 times at year-end. As a reminder, there are no bond maturities until 2020.

During the second half of 2014, our technical teams illustrated outstanding performance. We are proud of the value added through our better-than-600% reserve replacement, and a significant increase in year-over-year production. While pleased with our 2014 accomplishments, we are now intensely focused on 2015 and beyond.

Experience in the drop in oil prices, and our desire to prepare for sustained low prices, prompted us in February to proactively request an early re-determination of our borrowing base. And an amendment to our credit facility which considers the future effect of low oil prices on our total leverage ratio covenant. With the significant increase in reserves in our PDP reserves supporting our request, our lenders agreed to maintain our availability under the facility at $900 million -- even a materially lower oil prices.

We executed an amendment that includes a new senior secured leverage ratio of 2.25 to 1, which replaces the total net leverage ratio covenant of 4.5 to 1, until June 30, 2016. And added an interest coverage ratio as a covenant. The amendment also allows for $500 million of additional debt capacity in the form of a second lien or unsecured debt. The amendment is fully described in our 2014 10-K filed today.

Now let's discuss 2015 guidance. With the lower product-price environment, our focus is on preserving liquidity, cost efficiency and capital allocation. We'll achieve these objectives by concentrating our reduced capital expenditure plan on drilling our lower-risk, high-rate of return opportunities in infrastructure-efficient locations. Improvements in drilling and completion designs, lower cost well site production facilities, and utilization of pad drilling.

These efforts, combined with a larger percentage of our planned wells being multilaterals, and the cooperation of our service providers in supporting well cost reductions, will drive our current lateral costs significantly lower. Maintaining rates of return approximately equal to those previously experienced at an $80 oil price.

Our guidance table is included in the shareholder update on page 9, and as is slide 18 in the slide deck. Slide 19 has capital expenditure guidance detail. We are reducing capital expenditures by 56%, from our $1.6 billion in 2014 to a planned $700 million in 2015. Our capital expenditure plan is expected to support production between 28 million and 30.5 million barrels of oil equivalent.

We are ramping our drilling rigs down, from 32 rigs running at the beginning of 2015 to 7 rigs for mid-2015. So our capital expenditures will be heavily weighted to the first quarter, as this quarter will be approximately 40% of the total year plan. We expect cash G&A costs to decline year over year, primarily due to our consistent efforts in controlling cost.

I would also like to point out that, in an effort to reduce share dilution, starting this year, the long-term incentive plans of the Company included in G&A are settled in stock or cash. Unlike stock grants of the past, these are subject to quarterly valuations, which could significantly fluctuate with the share price. And cause both meaningful increases or decreases in G&A expense for any period. Operator, that concludes my remarks. Please open the call for questions.

Thank you.

(Operator Instructions)

Your first question comes from the line of Charles Meade from Johnson Rice. Your line is open.

Good morning, everyone. Thanks for taking my question. James, you guys have a lot of great detail in the slides this morning, and thank you for that. If I could get two questions in.

First, can you talk a bit about how your quarterly production progression is going to be? I'm guessing with the way that you guys are coming into the year, of running at 32 rigs and then going down to 7 by mid-year, that we're actually going to see the back-half of the year lower than the front-half. But I just wanted to test that with you.

Yes, that's right, Charles. So we had 31 rigs to start the year. We're at 19 now; we'll be at 7 by mid-year. And just in terms of CapEx dollars, we're spending 40% of our budget in the first quarter.

So yes, in the back-half of the year, we'll have production declines. And if you want to look at it as a lot of industry has been, on a fourth-quarter exit-to-exit rate, that would be a mid-teens production decline. So 6% growth year over year, exit-to-exit, a mid-teens decline as we, again, go from 31 rigs down to 7.

Got it. That's exactly what I was looking for, James. And then the other thing, if I'm doing this math right -- so 40% of your $700 million capital budget is going to be Q1. That's $280 million. That leaves you with -- let's see, where's my math here? That leaves you with $420 million for the rest of the year. If you annualize that, you're still at a run rate -- in the last three quarters of the year, you have about $560 million.

So the out-spend is diminished quite a lot, but you're still out-spending. And the way I have it modeled, with the relatively lighter hedge position in 2016, your cash flow is actually going to go down in 2016, at the current strip. Can you talk about what you're posture is in the back-half of 2015 -- if you're comfortable still over-spending in the back-half of 2015, going into 2016? And what your sensitivities are there?

Sure. If you look at, call it, 40% in the first quarter -- it's actually probably going to be a little more than that, just to get exact on it. But we'll be at kind of $100 million to $125 million a quarter, in the last two quarters of the year. So maybe a little steeper in the first two quarters, and then in that $100 million to $125 million in the back-half of the year. That will shrink that cash flow gap quite a bit.

And look, as I said in the prepared remarks, we recognize we need to get this cash flow gap down. We will be raising a couple hundred million dollars this year to fund that. We also have over $1 billion liquidity to start the year. So we're comfortable with that, and we will look for moves to strengthen that in 2016. You're right, we lose our -- largely the impact of our hedges.

Although we still have a reasonable hedge position in 2016, not 10 million barrels like 2015. So we will look to make some changes between now and 2016 to shore-up that funding gap.

If I could sneak just one more in, James, since you brought it up. The $200 million in asset sales -- is there any more detail you can offer on that? Is that the midstream or is that E&P assets? I think you mentioned something along that front.

Yes, I'd love to not give details on that, Charles. I don't understand why you would ask for it. We have several things in mind. We've talked about them in the past. Mostly, really all kind of non-core assets. But as soon as I give too much detail, it lessens my ability to get anything done.

Right.

But we've definitely targeted $200 million.

Thank you for that detail, James.

Thank you, Charles.

Your next question comes from the line of Neal Dingmann from SunTrust. Your line is open.

Good morning, James. [Neddy safe] James, couple things here. First, just a great slide that you've got on that type curve and cause. I'm just wondering where you have the sensitivities? What is that -- side 9.

Could you walk through a little bit on -- I think you're targeting there the $2.4 million D&C cost. How does that factor in with infrastructure and the water disposal, et cetera?

And then is that assuming -- I forget already the cost -- the service benefits that you're already seeing? Or could you even get some more on top of that?

Sure. Last year we were at $3 million well costs, and we're bringing those down rapidly. So our goal is to -- for the back-half of the year, to be at this $2.4 million well costs. And as I mentioned in the prepared marks, we've actually already taken about $250,000 out of that $600,000 goal.

So that's our goal -- $2.4 million. Feel very confident that we can reach it. And it's a combination of three things -- efficiency gains from using our best rigs, and shortening the cycle time and less trouble time, changes to completion and wellbore design, high-grading pads, things like that. So if you look at page 8 there, the first set of real efficiency gains.

The second, area, which is about another 40%, are the service cost reductions that you've talked about. Yes, we've already gotten many of those in place. Some, we're still working on getting those down. But of that $250,000 I mentioned we've already achieved, a lot of that is still in service cost reductions. So that service cost reduction.

The next piece is an increased use of multilaterals. So again, very confident that we'll get this well cost down to $2.4 million in the back-half of 2015, which sets us up for very nice economics for that period.

You asked also about infrastructure. We quote D&C returns because that's pretty standard in the industry. Our disposal, our water-gathering infrastructure, is about $250,000 per well. I think if you look at the exact math on our guidance, it comes to $265,000, but it's right around $250,000 this year.

And that takes about 10 percentage points or 1,000 basis points off your return. So that 45% return goes to about 35%, including that $250,000 of saltwater gathering infrastructure. And that includes the cost to drill the well and the pipes to connect it, as well.

Got it, okay. And then, James, moving over to slide 11, where you guys nicely lay out the reasons that you're going to be drilling in. How different do you all, when you have your estimates out there, either for the EURs, et cetera? I mean, do you view that -- let's call it, the western Woods versus eastern Grant. And then when you get up into Harper, I mean, is that area -- do you view pretty contiguous there now, James, when you've locked in on this focus area?

Yes, and I think we have a good understanding of these areas. Now, they're different. Down in Garfield, you'll see a little hirer GORs, but a very tight distribution of returns. Alfalfa is going to have our biggest oil rates.

Woods is going to have a little flatter decline. And Harper, with some increased entity stimulations -- the new stimulation techniques we've done, we've seen really good rates. So yes, we have a much deeper understanding of the play, now that we have over 1,400 wells and over 2,000 miles of seismic.

All right. And then just lastly, when you look at -- again, what I'm looking at is liquidity for the end of this year and into 2016. James, when you're thinking about CapEx and then the cash that you have now, how do you envision the -- without giving us a 2016 plan, is it more when you and Eddie discuss a minimum liquidity amount that you (technical difficulty) at a leverage metrics? Or how do you think about when you go about -- when the Board meets next time, to think about the activity?

Sure. Liquidity is always paramount. You never want to be forced to go get capital when you really need it. So we'll maintain a long liquidity runway. That's going to involve our borrowing base, it's going to involve paying down any drawings, it's going to involve this $200 million sale of asset proceeds. That's the first lever.

And the second is leverage. And this covenant amendment gave us plenty of time to get some of these more strategic things we're thinking about, done. So we'll make sure we keep the leverage and liquidity in check. And importantly, this covenant amendment gives us plenty of runway.

Make sense. Thanks, James.

You're welcome.

Your next question comes from the line of Ben Wyatt from Stephens. Your line is open.

Good morning, guys.

Good morning, Ben.

James, maybe we can -- some good things going on operationally in the mid-continent. Maybe we can talk a little about the Chester and Woodford. Nice wells you guys mention in the press release from last quarter.

Just any update you can give us there? And then how wells that have been online a little bit longer, how those wells are holding up versus expectations?

Yes, good question, Ben. So on the fourth quarter, we had three new Woodford wells. They were just under 400 BOE per day on a 30-day IP. That was about 77% oil. And we had 10 Chester wells in the fourth quarter -- 470 BOE per day, about 60% oil. So continued good program there.

And let me just tell you where we are for the full year. Remember, we changed our Woodford design. So under this new geologic model, we're calling it, we have five wells on line, 30-day IPs on those, about 415 BOE per day -- and that's 79% oil. We think the EUR on this program is about 250,000 to 275,000 barrels of oil equivalent per well, on our Woodford program.

And let me just switch to Chester. Chester -- again, 10 wells, 470 BOE per day, it in the fourth quarter. The Chester program's 37 wells -- the 30-day IP is 360 BOE per day. And that's about 60% oil. And EUR on that we estimate is about the same, about 250,000 barrels of oil equivalent, again. But about 60% oil.

In our 2015 program, we don't have a great deal of Chester and Woodford drilling. One, we're wrapping up the tail-end of this Woodford program under the new geologic model. Once that's done, we'll re-evaluate.

But as we high-grade our wells, with a Mississippian well costs coming down so rapidly, those returns are actually superior right now. I think our teams will get our Chester and Woodford well costs down. And those will be a bigger piece of the program. But for right now, in an area of highest capital efficiency we can possibly get, and $2.4 million well costs, our Miss wells take front stage there.

Very good. Well, that's all for me, guys. I appreciate it.

Thank you.

Your next question comes from the line of Tarek Hamid from JPMorgan. Your line is open.

Thank you and good morning. On the well economics, can you talk a little bit about the sensitivity of the gas prices? Just give us a little bit of color about how to think about that?

Yes. On the pay, if we've got a scale there on oil, but I don't think we have quite given the scale on gas. So I don't actually don't have it right with me, the sensitivity of the gas price on the curve. But we can follow up and get you that.

Helpful. And then, as you think about your voluntary discount, and certainly you have now the flexibility to look at second [links] as well, just talk a little bit about capital allocation. Within your capital structure, how do you think about the [discount year] bonds and next steps, as you look at your [volume] liquidity and leverage evolution?

Sure. Recognizing that $3.2 billion in debt, as I mentioned in the prepared comments, is high, relative to our asset base. Adding that to the balance sheet is not high on the list, but if we need to do it for liquidity or other reasons, we certainly can.

As you know, we have a pretty big [more] restrictive payments basket under our indentures. And also ability to secure additional liens in the neighborhood of $1.75 billion. So those levers are available to us, and we keep those in mind, and have ideas around those.

But I think either growing the cash generation ability of our asset base to get in line with the balance sheet, that was certainly evident at $90 oil. And we had that in our cross-hairs at $50 to $60 oil -- less easy to do. So I think shrinking the debt level is probably the next logical alternative here. I don't know if that fully answered your question.

No. That's helpful. And then just as you think about that CapEx budget for 2015, given your exit rate decline by year-end, do you have any preliminary thoughts on what kind of a similar decline rate, or even just a maintenance-ish capital budget, would look like for 2016?

I don't for 2016. We're not ready to give 2016 guidance yet.

Okay, fair enough. That's my last question. Thank you.

That's all right. Thank you.

Your next question comes from the line of Richard Tullis from Capital One Securities. Your line is open.

Thanks. Good morning, everyone. James, I see the decline in the oil for this year versus where you were in fourth quarter, and you explained that in the opening comments. Do you expect the oil percentage of total production will decline further in 2016, given the gas year component of what you'll be drilling this year and the minimal Permian activity?

I don't have full-2016 guidance to give out. If you look at our type curve, the initial decline on oil is 80%. On gas, it's roughly 65% -- 62% to be exact.

So if you stop drilling today, your oil is going to decline a little faster than your gas. Now as you get out two and three years, that decline starts to moderate and flatten out a bit. So the longer you go with declining production, the flatter it starts to get.

So I'm not really ready to give 2016 guidance yet. If you wanted to play around with the type curve, you could try to model it out there. But the oil, certainly -- initial decline at 80% versus gas at 62% or 65%, will point you in that direction.

Okay, thank you, that's helpful. And how many net wells are you expecting to bring on line in 2015?

About 180 gross wells, and 120 net.

Okay.

And then, we talk in terms of laterals. To be exact, it's 116 in our development program. But we talk in terms of laterals, because as you know, some of those wells will be multilaterals. So we equate it to a 4,200- or 4,500-foot lateral.

And you're expecting these wells to be in the average of the PUD EUR?

Yes. Now, we're not drilling all PUD wells. I believe this year we said that about 70% of our wells will be real PUDs that we drill, versus a third last year. So they're not all going to be PUDs. But 70% of them will be PUDs.

Okay. Looking out into, say, 2016, 2017. I know you're not ready for guidance at this point, but just in general. Do think you'll be spending more on infrastructure saltwater disposal-related expenses per well in those years, since the 2015 wells are all drilled near existing infrastructure?

No, one of the goals for the Company is to get our non-D&C spending down. We can generate great rates of return on the well, and then you put the infrastructure on it, it takes it down a little bit. But still very good returns.

But I want to get that down over time, and to get more efficient with our infrastructure. As our existing base of production starts to decline, you can connect more wells to existing gathering systems. And we tie it in, and we are very careful and methodical about how we develop the field.

I'm not ready to say exactly what it's going to be, but I want to get that saltwater gathering number down over time. But keep in mind, I still think that water-gathering business is a valuable midstream business. And the capital we do spend on it, I believe will get that back, plus.

Okay. Any risk of significant acreage expiration, given the seven-rig program in the second half of this year?

Going into this year, we had 715,000 net acres in the mix -- actually up a bit from the last number you probably saw. So we ended the year at 715,000 in the focus area.

We have 113,000 acres expiring in the focus area this year. We have options to renew on 14% of those for around $7 million. So for $7 million, we can keep 14% of that.

We will let a lot of that acreage expire this year. It's not in and around areas we're drilling.

So we think we'll end the year at 625,000, something in the ZIP Code, 1,000 acres, which is still plenty. We were talking -- most of last year, we talked about 650,000 to 750,000 acres. Again, into 2015, we'll be in the probably 625,000-acre area, which is plenty.

Just to give you the number, in 2016, we have 100,000 acres expiring, options to renew on 26% of that for $10 million. So we can, again, renew some more in 2016.

But keep in mind, we're not going to drill the whole acreage. But I will say, in this market, sometimes you're better off letting the acreage expire and re-leasing it.

Because it's cheaper nowadays to re-lease than when these leases were signed, sometimes in 2010, 2011, 2012. So in a lot of cases, you let it expire, and you go re-lease it for cheaper.

Thank you, and that's all for me. I appreciate it.

You welcome.

Your next question comes from the line of Adam Leight from RBC Capital Markets. Your line is open.

Good morning, everybody. Just a couple of clarifications here, if I can. On the borrowing base, is that $900 million -- that's the new borrowing base rather a voluntary commitment level?

Correct, that's right. That is the new borrowing base.

And do you have any sense today where this might go in the fall?

Adam, let me give you a couple of data points. The price deck that the banks used, as you're probably hearing, was actually -- is below where the strip is right now. And the coverage we had from the PV-9 of our PDP -- which, as you know, that's how the banks calculate it -- plus the value of our hedges, the coverage of that over that $900 million was 1.7 times.

So I don't know exactly how the banking community is going to behave in the fall. I think they'll be pretty reasonable, in terms of how they treat the industry.

They certainly have been so far. But we think with the reserves we can add between now and then, and a 1.7 times coverage that we had now on a price deck that's below the strip, we feel very good about of our borrowing base.

Okay, that's helpful. And then just an extension of that -- thank you for providing the strip PV-10. Can you break out the net amount for proved developed on that same calculation, [that centered]?

Yes, I can, Adam. Let me give you that number. So we said the PV-10 was 3.3 billion at strip pricing. Proved developed is 2.7 [billion], and the PUDs, 600 million. So not a big impact from the PUDs. That's 2.76, and that is at our last 12 months of well cost, which is in the $3 million range. But 2.7 [billion] is, I think, the number you wanted.

That's great, I appreciate that. And then, you've talked a little bit about the well declines and mix. Where do you estimate the current overall corporate decline? And what do you think that might look like after the spending is done at the end of this year?

I can say this. I don't have a projected one, Adam, of what it will be a year from now, based on the wells we're going to add. I will say that at the start of the year, if you just halted drilling altogether for the whole Company, you're on a 35% exit-to-exit decline. That would be the PDP decline based on everything we have on production at the start of the year. Does that help?

That's great. Yes, that's very good. Thank you, appreciate it.

You're welcome.

Your next question comes from the line of Jamaal (inaudible) from PBH. Your line is open.

Good morning, guys.

Good morning.

Most of my questions were already answered. I was just wondering if you've received any updates on that GOR, just to get a small update there?

Sure. We have not -- the IRS for some time has said they've been close. We don't really know what that means in IRS Land. So we're controlling the variables we can control. We're keeping our S-1 active. We're updating that. We're investing in that business, and continue to optimize it, and look for other opportunities for that business. But we'll keep the S-1 active, and we'll see what happens with the IRS over the coming months and quarters.

Okay, great, sounds good. And operationally, I'm just thinking about the long lateral tests, and the full section of development. Could you give some details on the results of the long lateral? And for the full section, was that $2.3 million per lateral before service cost reduction -- so at Q4 well cost levels?

Yes. It was actually a Q2 and Q3 well cost level, really -- Q3 well cost level. So yes, that's before service cost reductions.

And remember, we said our total multilateral program was at $2.6 million last year for just under 30 wells. And we think we'll be able to get that in the low-$2 millions. So the full-section development has gone very well.

I would say that on the full-section development, that well IP-ed close to 1,100 BOE per day. And its 150-day cumes are 100% on oil, in terms of 4 times our new type curve. And on a BOE basis, they're about 90% of the 150-day cumes.

So again, much less cost, for right at very close to the cumes you would get for single wells. The long lateral was in a very good area, with results well over 1,000 barrels of oil per day.

Okay, great, sounds good. Just last thing from me, the Comanche [SE] -- that there isn't really any drilling directed there on the plan, from your slides. Is that because of infrastructure?

It's more so because from the GOR, very high gas in Comanche. At a different gas price -- we refer to it as potentially the gas bank -- but at a different gas price, it could deliver some very strong gas rates. We've worked on the completion methods there, and know that increased density is the way to go.

So we can drill there, and will at some point. But it's probably more of a gassy area than it is liquids and oil.

Great, that sounds good. That's all for me, thank you.

Your next question comes from the line of Owen Douglas from Baird. Your line is open.

Hi, guys, thanks for taking my question. Thankfully, a lot of good questions have been asked before me. But wanted to ask a little bit on the capital structure. So typically, the preferred units, those ones -- are you able to defer the cash payments on those? And have accrete and principle value? Or do those cash payments need to be made?

No, we have a couple options there. We could pick them, or for -- I believe it's three quarters without any consequences, we can not declare those dividends. And I think it's safe to say in this current environment and us watching liquidity, we don't plan to pay cash dividends on our preferred dividends in the near future.

Okay, that's helpful to know. And also, I believe that at least a couple of those have some managerially convertible features that you guys can exercise. What are your thoughts surrounding the exercise of those?

Well, a couple things. There was one that mandatorally converted in December. Remember, we had 765 million of preferreds; now it's 565 million. I think that's the mandatory you're thinking about. The others convert at a premium to their conversion price, that's the only way we can convert them, and they're pretty far out of the money right now.

Oh. I thought you guys had the option to essentially force the holders to convert them. Is that not the case?

No, that's not the case. That was just -- the first one was in December, the automatic conversion, that automatically converted. These others, we can only force conversion if it meets that 130% of the conversion price.

Okay, that's great. And also, it sounds like you guys are very much focused on liquidity and maintaining liquidity. But there's two ways to go about it.

One, you can invest in really high-return projects and have the Company earn its way out of its high leverage. The other way is to try to cut back on the production and the investment, to try to live within cash flows. How do you think about which of these two options are preferable at this point in time?

Yes, exactly. At $90 oil, it was the latter. We had enough of, plenty of high-return projects that we could invest and comfortably grow into the balance sheet. At this lower commodity price environment, I think it will be the latter.

I think it will be scaled back, watch our dollars very carefully, try some balance sheet enhancements in terms of raising some capital where we can. So I think it will be the latter. I think it will be slowing down a bit, as opposed to ramping up the drilling program.

That's great. And speaking -- and just wanted to drill down a little bit further in the comments you just made on balance sheet enhancements. Can you provide a little more color on that, just in terms of what some of the options are, how you think about their pros versus cons?

I really can't in too much detail. Charles Meade asked about it earlier. We have targeted $200 million in capital to raise this year, from asset sales or monetization. So that will help supplement it.

But we either need to grow our cash generation ability on the assets we have, or shrink our level of debt. Those are our two options, and I'll just leave it at that. We're very focused on liquidity and getting closer to within cash flow and reducing our overall level of debt.

Okay. I will hop back in the line now. Thanks very much.

Thank you.

Your next question comes from the line of Gregg Brody from Bank of America. Your line is open.

Good morning, guys and thanks for all the detail. Just on the working capital side, with the cut in the rig count, what's the expectation for the payments for your payables, in terms of cash outflow?

You know, with going from 31 rigs down to 7, and the CapEx budget going from $1.6 billion to $700 million, yes, we will have some working capital use this year, particularly early in the year. So as you look at cash burn early in the year, keep in mind that's working capital-related. Some of that we'll get back later in the year, but it will be a little lumpy in terms of the quarter-to-quarter cash, when we go from $1.6 billion capital down to $700 million.

If I look at your working capital, there's a net balance of about $350 [million]? Is $350 [million] a good number? Or is it much lower, or is -- what's a ballpark?

I don't know, I'm not really ready to project year-end working capital right now. I just know that we will use a little this year as we decrease our activity level.

Okay. And then just your lifting cost, [there's only often not] in this environment. I was just curious, what's the driver of that?

Sure. It's primarily growth in our use of ESPs, our Electric Submersible Pumps. In 2014, we had almost 100% use of ESPs. In 2013, that was about 60%.

We went from, in January of 2014, 400 ESPs. We ended the year at 900. We actually had a pretty big ESP conversion program. Gas lift to ESPs is about 185 we changed out.

What it does is, greatly increases your power consumption. Our power demand increased about 88% last year. So power is a big component of the LOE.

And so we increased our power consumption 88% from 63 megawatts, about 118 megawatts. That's the lion's share of it.

So increased LOE. But the ESPs do create a lot of value. They give you higher production rates and they prove the abandonment pressure at the end of the well, so it improves your ultimate recovery, so it's a good trade-off.

Great. And then just last one for you, just on the differential side. It looks like those are a little higher. Is it just simply the fixed costs are a greater percentage of the [oil] prices? Or is there something going on in the fields?

No, it would just be the transportation component, which doesn't move as much when your commodity price moves.

That's what I thought. Thank you very much.

You're welcome.

Your next question comes from the line of James Spicer from Wells Fargo. Your line is open.

Good morning, everybody, thanks for taking my call. You mentioned that this $200 million of potential monetizations would fill a large portion of the funding gap this year. Just wondering, based on your number, what's the total cash flow gap that you're trying to fill this year?

If you take the midpoint of guidance, depending on what price deck you're assuming, but it's about a $550 million EBITDA. Less $250 million of interest expense on a $700 million capital program -- these are all round numbers -- is about a $400 million delta.

Okay, got it. And I know you don't want to give too much away in detail on the asset monetizations, but do you have anything you can provide in terms of just timing? And is this process already underway?

Are there things that are being marketed right now? Or is this later-in-the-year kind of timeframe?

Yes, this will be opportunistic, and probably later in the year. We're not in any rush in terms of our liquidity. We have plenty of runway and time, so we'll be making sure we get the right value for that, and not rushing to get anything done. But don't expect anything right now.

Okay, great. And then lastly for me, just your guidance in LOE for 2015, what's driving the year-over-year increase in that?

Similar to the answer of why it was up a little bit in 2014 -- increased power. A couple things.

Our power consumption went up 88% year over year because of increased ESPs. You roll that forward for a full year, and you get slight increase in LOE. That's the primary driver.

All right, thank you.

You're welcome.

Your next question comes from the line of Dave Kistler from Simmons & Company. Your line is open.

Good morning, guys.

Good morning, Dave.

Real quickly, with the 1,400 wells that you have on line and 2,000 miles to 3D and the uplift that you guys saw on IPs in the fourth quarter, can you talk a little bit about the standard deviation of a well results? Are they getting tighter in terms of hits and misses Just any color there would be great.

Yes, sure, Dave. As you can imagine that, the first year we had 37 wells in the dataset; the second year, 145. Now we have over 1,400. We had no seismic going back to early part of the program.

So yes, a much better understanding and a tighter distribution around the returns. For example, in the area of northern Garfield that I've talked about, you have returns are slightly above type curve.

But the variability from your bottom set of the wells to your top set is 68% less than what we saw in early results of the play. So that's just one example.

And probably on our next round of conferences, we'll come out with some pages on distributions over the years and such. But yes, we've absolutely been able to tighten that distribution. What you can see in our low finding costs of $9, and a 600% reserve replacement, and adding over 140 million barrels -- all of that the function of drilling the right wells in the right spot for less dollars.

Great, appreciate that. And then one other just -- when you guys were talking about the IRRs between the Chester-Woodford and the Miss. Chester-Woodford, I think, primarily single laterals, and the Miss, moving more towards multilaterals. Are you going to test multilaterals in Chester and Woodford? And could that make them more competitive in a redirection of capital?

You know, we've talked about that. I could see us doing longer laterals in some of those plays, maybe more than multilaterals. One of the reasons the multilaterals work so well in the Miss is because it's a carbonate hard rock with a lot of structural integrity. So you can leave the wells open hole.

If you go in the Chester, and even in the Woodford, that's not -- in the shale, it's not as much of an option to leave an open hole. You would have a lot of cement, cemented liners, whip stock, things like that. So the multis are a little more complicated in those two, but the longer laterals might be a better application there.

Great, appreciate that. And one last thing, just to the LOE question, that you were highlighting essentially that power costs are driving that a little bit higher, with lower commodity prices. I imagine lower power prices follow suit. Should we expect to see that trend down?

No. Power doesn't fluctuate with commodity prices all that much. Certainly not as much as gasoline or natural gas. You won't see your power move much when commodity prices shift. That one is a little more elastic.

I will say on LOE, it's important for us and we watch it and we have goals around it. It has a much smaller impact on our returns in PV than the up-front CapEx does.

When you've got -- the LOE in the Miss is about $8. A 10% improvement in that only changes your IRR by a couple hundred basis -- by 100 basis points over the life of the well. So while impactful, not near as impactful as a CapEx savings.

Okay. Really appreciate the added color there. Thanks so much.

You're welcome.

Your next question comes from the line of Amy Stepnowski from The Hartford. Your line is open.

Hi, thanks for taking my question. Just a follow-up on the hedge book. Obviously it drops off pretty significantly towards the end of the year. Granted, prices are quite low. But as you're thinking about trying to put in a base case plan, can you just elaborate a little bit about what your thoughts are on hedging and adding to the book?

Sure. So we have over 10 million barrels hedged this year, and about $4 million of oil hedged in 2016. Depends on how contango the strip is.

But I think for our business, at the -- $75, $70 oil range, would look pretty attractive in terms of locking in returns in some of the out years. But right now with the strip, $55, getting into the $60s, I don't see us hedging right now at these levels.

Okay. And with regards to gas, any thoughts on that?

Yes, probably similar. With a decline in rig count, I do think in a year from now or so, you're going to see some rollover in gas. So we're looking to stay unhedged in terms of gas. Recall though that oil still comprises about 65% of our revenue stream. So oil is a primary driver here.

Okay. And then the last question, just a clarification of a comment you made earlier with regards to the fourth-quarter 2014 compared to fourth-quarter 2015 exit rate. I think you said mid-teens. Was that for total production?

And if that's the case, would we expect that the decline on oil would be greater than that? Or did I misunderstand, and that was actually the decline for oil from Q4 to 2015?

No, I think you understood it correctly. That would be the total decline. That would be on a BOE basis. And we said that oil decline is a little steeper than gas in the first year, so I would expect oil decline to be a little steeper, and the gas to be a little more shallow, in that mid-teens number, if that helps.

Yes, it does. Great, thank you so much.

You're welcome.

(Operator Instructions)

Your next question comes from the line of Brian Salvitti from Guggenheim. Your line is open.

Hi, guys, thanks for the update call here. Just a follow-up on -- and apologies if I missed this -- on the IRR chart on the curve, you're showing the 45% to 40% IRR. I want to see what percentage of your inventory or PUD wells does that IRR apply to? Or how should we look at the acreage that you're going to be executing on, with regard to that IRR?

Sure. This is the PUD type curve, so we will drill about 70% of our wells of the 180 laterals this year. About 70% of those will be PUDs, and the remainder will be non-PUDs.

This is the average of our PUD program, so this would be close to what the 70-well program would deliver. And then we'll see on the remaining 30%. We hope they're better than type curve. But they are non-PUD wells.

And does that commentary go as well for the increase in EURs that you were highlighting as well, too?

Yes, it would. That EUR is, as of -- is for a PUD well. So the IP in the EUR would be for the -- 70% of those would be for PUD wells, yes.

Okay, all right, great, thanks. And then the last one is just on the amendment to the borrowing base. We saw there's commentary for junior debt up to $500 million. Just trying to understand what was the rationale for that? And then, is that senior to the bonds, or just a little bit more detail on just that carve-out?

Sure. We would have the ability to do, call it, junior lien debt, second lien debt, which would be senior to the bond. So we could do additional unsecured debt. We put that in there because I think liquidity, particularly in this market, is of paramount importance.

Not that we need it right now. But in case we do, we want to have a mechanism to have access to that $500 million. So it could be in second or even third lien or some kind of junior lien. It could also be unsecured.

Okay, all right, great. Thanks so much for the time, guys.

You're welcome.

Your next question comes from the line of Andy Parr from [Surveyor]. Your line is open.

Andy, are you there?

If you're on mute, please unmute your phone. Mr. Parr, your line is open.

We can go to the next caller, operator.

Thank you next question comes from the line of Sean Sneeden from Oppenheimer. Your line is open.

Good morning, guys.

Good morning.

As a follow-up to the last question there, James, as you think about, strategically, the whole cap structure here. What do you think is the appropriate amount of debt to have on the business?

Obviously having the flexibility to do second lien or what have you, gives you optionality. But as you said, I think, in your prepared remarks, do you think $3.2 billion of debt is too much? How do you think about what the appropriate capitalization of the business should be in the current environment?

Yes, at current commodity prices -- so at the strip, our PV-10 was $5.5 billion. I'm sorry -- at SEC, it's $5.5 billion. At the strip, it's $3.3 billion. So the question really depends on what price you're assuming.

You said at the current price environment. So if things didn't change, I think, one, we'd see service costs come down even more, and some more opportunities available in the business. But if nothing changed, you'd probably want to remove $1 billion of debt from the balance sheet.

So we'll come at it several different ways. I don't know if we're going to try to grow the cash generation capability assets. And I think we will get commodity price improvement, which is one of the reasons we want to make sure time is on our side.

So it depends on a lot of different factors. If the world stayed the way it was today, you'd probably want $1 billion less debt.

Sure, makes sense. How do you guys think about doing more of a strategic type of transaction? I think you probably have seen some of the announcements by some other operators like Jones and [Lynn]. Are those things that you guys are considering in terms of reducing overall cash costs or cash CapEx to you guys? Or how do you think about that?

Yes, those are ideas in the toolbox. Structures like those, or joint ventures or selling non-core assets, entering into drilling partnerships. There's a lot of different ways to go about increasing your cash generation without taking on debt or reducing the right-hand side of your balance sheet. So sure, those are all options that we have on our list.

Okay, that's helpful. And just lastly for me, for your Eddie, just wanted to clarify. So the release said that you're spending, about $430 million in this mix this year on CapEx, and $600 million or so on total E&P CapEx. Is it fair to assume the remaining of portion of that is for the Permian? And how much of that is going to be discretionary?

You know, there's actually no Permian spending this year. So that D&C, that roughly $450 million -- you have 300 million of that is for new development this year, and that's all in the mid-continent. So no Permian spending this year.

Okay, that's helpful. Thank you.

There are no further questions at this time, presenters. I turn the call back to you.

Thank you all for joining. Look, while this oil price environment is challenging, we are taking bold and appropriate steps to ensure success in this market -- lowering our CapEx lowering our well cost, watching all areas of spending. Heightening in on the best areas of the play, where we can generate consistent good returns. And then looking for ways to increase our cash flow and shore-up the balance sheet.

So know that you've got a team of people here all focused on that, and do the right things and create returns for the shareholders. I thank you all for your time.

This concludes today's conference call. You may now disconnect.