SandRidge Energy, Inc. (SD) Q4 2014 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. Welcome to the SandRidge Energy’s Fourth Quarter 2014 Conference Call. At this time, all lines are in a listen-only mode. After the speakers’ remarks, we will conduct a question-and-answer session. [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 Web site 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 risk 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 Web site. 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, and welcome to our fourth quarter 2014 call. As we move on beyond a volatile 2014, we’re all living in a price environment that has markedly changed since we last spoke. My goal today is to leave you with the clear vision of how we have 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 plan and 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’ll highlight a few of our successes from 2014 but focus most of my time on how we have positioned 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 MidCon production grew 47% versus the 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’ll give greater detail about in a moment. These new costs and our improved type curve combine to make us competitively capital efficient even in this price environment. Our 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 re-determined our borrowing base and maintained our 900 million availability. Recall that at year end, we had over 180 million in 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 yield 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 seven rigs 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’ll lay out the crust 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 or better than our prior returns at $80 oil and 3 million well costs. As we’ll discuss, those lower costs are not just the product of service cost reductions but even more so real operational efficiencies. Most of these are durable in 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 for just 85% of the cost of a single lateral. So with our type curve increasing, cost coming down plus the advantages of multilaterals, we’re able to maintain returns in 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 is additional downward movement in the market. I’m very pleased with our reserve performance and message. Take a look at Page 6 of the presentation sides. Recall in 2014 we tightened our development efforts to concentrate in areas of play where we have the best result and can generate high returns. Through this focus effort, we’ve been very successful at growing our proved reserves this year adding 143 million barrels of oil equivalent through the drillbit 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 costs of $9 per Boe. At SEC pricing, PV-10 grew 34% to 5.5 billion. I recognize year-end SEC pricing isn’t indicative of the current market. We calculated PV-10 based on recent strip prices, which average 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 early throughout the year, we have achieved continued outperformance 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 started 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 whose 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 and operational improvements, reducing 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 and trouble time, changes to completion methods and wellbore design, location high grading, increased use of skid pads and commingled tank batteries. These efficiencies will continue to enhance return no matter what future price environment we operate in. The second, improved pricing will account for about 40% of the total. This is coming from several years 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 these savings. We’re going from 20% multilaterals in the back half of 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 that multilaterals’ 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 how can we develop a greater area of even a full section for lower costs? Our teams’ innovated and delivered on this. And through the success of dual laterals accessing the same zone, stack lateral accessing two stack zones and now we have proven full section development as illustrated on the 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 for 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 2x our standard lateral link. 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, 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 Miss 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 build the 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 performed at the upper end 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 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 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. This 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 midpoint. 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 the 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 projecting a slight 200,000 barrel decline in oil. This decline is a function of both 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 by 900 million, reducing well cost 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-EMP 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 will be further strengthened by the hedges we have layered in 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 collars. As an example, at $50 flat oil taking into account waiting of the swaps and three-way collars, 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, a 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 the backdrop of increased financial flexibility from our new borrowing covenants and existing hedges sets us up defensively for the current environment. Finally, I’d 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 success forward and you are all 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. In discussing EBITDA and production, I’m 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. 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 availability of approximately $900 million under our reserve based 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 3.8x 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’re proud of the value added through our better than 600% reserve replacement and the significant increase in year-over-year production. While pleased with our 2014 accomplishments, we’re 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 redetermination of our borrowing base and an amendment to our credit facility, which considers the future effect of lower oil prices on our total leverage ratio covenants. With the significant increase in our PDP reserves supporting our request, our lenders agreed to maintain our availability under the facility at $900 million even at 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 debt 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 us 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 expenditures plan on drilling our lower risk, high-rated 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 per lateral cost 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 is Slide 18 in the slide deck. Slide 19 has capital expenditure guidance details. 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’re ramping our drilling rigs down from 32 rigs running at the beginning of 2015 to seven rigs for mid-2015. So our capital expenditures will be heavily weighted to the first quarter. 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 petrol costs. 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, I guess, two questions. First, can you talk a bit about how you’re quarterly production progression is going to be? I’m guessing with the way that you guys are come into the year running 32 rigs and going down to seven by midyear 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 seven by midyear. And just in terms of CapEx dollars, we’re spending 40% of our budget in the first quarter, so yes. And the back half of the year, we’ll have production declines and – if you want to look at it, as a lot of the industry has been on a fourth quarter exit rate. That would be kind of a mid-teens production decline, so 6% growth year-over-year, exit-to-exit kind of a mid-teens decline as we again go from 31 rigs down to seven.

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, so that’s 208 million. That leaves you with – let’s see, where’s my math here. That leaves you with 420 for the rest of the year. So if you kind of annualize that, you’re still at a run rate. And last three quarters you had about 560, so the doubt spend has diminished quite a lot but you’re still out spending. And the way I have modeled with the relatively lighter hedge position in '16, you’re cash flow is actually going to go down in '16 at the current strip. Can you talk about what’s your posture is in the back half of '15 if you’re comfortable still overspending in the back half of '15 going into '16 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. So that will shrink that cash flow gap quite a bit. And look as I said in the prepared remarks, you’d recognize we need to get this cash flow gap down. We will be raising a couple of 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 largely the impact of our hedges while we still have a reasonable hedge position in 2016, not 10 million barrels like '15. So we will look to make some changes between now and 2016 to sure up that funding gap.

If I can sneak just one more and 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 EMP assets? I think you mentioned something on that front.

Yes. I’d love to not give details on that, Charles. I don’t understand why you’d ask for it. We have several things in mind. We 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. So we’ve definitely targeted $200 million.

Right. Thank you for that detail, James.

Thank you, Charles.

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

Good morning, James and Eddie. James, a couple of things here. First, just a great slide that you’ve got on the type curve and costs. I’m just wondering you had the sensitivities, I guess, what is that, Slide 9. Could you walkthrough a little bit on, I think you’re targeting there the 2.4 million D&C costs. 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 already seen or could you even get some more on top of that?

Sure. So 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 had mentioned in the prepared remarks, we’ve actually already taken about $250,000 out of that $600,000 goal. So that’s our goal, 2.4. We feel very confident we can reach it. It’s a combination of three things; efficiency gains from using our best rigs and shortening the cycle time and less trouble time, changes just to completion in wellbore designs, 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 have 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 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 '15, which sets us up for very nice economics for that period. Now, you asked also about infrastructure. We quote D&C returns because that’s pretty standard in the industry. Our disposal or 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 in 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 of saltwater gathering infrastructure and that includes that cost to drill the well and the pipes to connect it as well.

Got it, okay. And then, James, kind of moving over to Slide 11. You guys nicely layout kind of the reasons that you’re going to be drilling in. How different – I guess when you have sort of your estimates out there either for the EURs, et cetera, I mean do you view kind of that – let’s call it the western Woods versus eastern Grant, and then when you get up into Harper, is that area – do you view pretty contiguous there now, James, when you’ve kind of 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 higher 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 density stimulations and 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, I guess when you look at kind – I guess what I’m looking at is liquidity for the end of this year and into '16. James, when you’re kind of thinking about CapEx and then just kind of the cash that you have now, how do you envision sort of the – I guess giving us a 2016 plan, is it more when you and Eddie discuss kind of minimum liquidity amount that you want to see. Is it 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. The 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 us paying down any drawings, it’s going to involve this 200 million sale of asset proceeds. That’s the first lever and the second 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.

Makes 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 operationally in the MidCon but maybe we can talk a little bit about the Chester and Woodford. Nice wells. You guys mentioned in the press release from last quarter. Just any kind of update you can give us there. And then maybe how wells that have been on line a little bit longer, kind of how those wells are holding up versus expectations?

Yes, good question, Ben. So in 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% of 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% of 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. So Chester, again, 10 wells, 470 Boe per day in the fourth quarter. The Chester program is 37 wells. The 30-day IP is 360 Boe per day and that’s about 60% of oil. And EUR on that we estimate it’s about the same, about 250,000 barrels of oil equivalent again but about 60% oil. Now 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 reevaluate. But as we high grade our wells with the Mississippi and 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 are Miss wells take front stage there.

Very good. Well, that’s all from me guys. I appreciate it.

Thank you.

Your next question comes from the line of [indiscernible] from JPMorgan. Your line is open.

Thank you and good morning.

Good morning.

On the well economics, you talked a little bit about for your new PUD type, the sensitivity of the gas prices, just give us a little bit of color about how to think about that?

Yes. On the page, we’ve got a scale there on oil but I don’t think we’ve quite given the scale on gas. So I 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.

That’s helpful. And then as you think about just sort of your bonds trading at discount and certainly you have now the flexibility to look at second liens as well. Just talk a little bit about sort of capital allocation within your capital structure? How do you think about sort of the discount on your bonds and sort of next step as you look at your kind of broader liquidity and leverage evolution?

Sure. Recognizing that 3.2 billion of debt, as I mentioned in the prepared comments, is high relative to our asset base, adding debt 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 one restricted payments basket under our indentures and also ability to secure additional liens in the neighborhood of 1.70 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 or our asset base to get in line with the balance sheet, that was certainly evident at $90 oil and we had that in our crosshairs 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, it’s helpful. And then as you think about that CapEx budget for '15 given your exit rate decline by year end, give any sort of preliminary thoughts on what kind of a similar decline rate or if just a maintenance-ish capital budget would look like for '16?

We’re not ready to give 2016 guidance yet.

Okay, fair enough. Had to ask the 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 as a component of what you’ll be drilling this year and then 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 was 80%, on gas it’s roughly 65%, 62% to be exact. So if you stop drilling today, you’re 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 ready really to give 2016 guidance yet. If you wanted to kind of play around with the type curve, you can try to model it out there. But the oil is certainly – initial decline of 80% versus gas at 62% or 65% will point you in that direction.

Okay. Thank you. That’s helpful. Then how many net wells are you expecting to bring on line in 2015?

About 180 gross wells and 120 net.

Okay.

And 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 multilateral, so we kind of 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. And 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 drilled versus about 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 you think you’ll be spending more on infrastructures, saltwater disposal-related expenses per well in those years since the 2015 wells are all drilled, near existing infrastructure?

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. 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 were very careful and methodical about how we develop the field. I’m not going 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 valuable midstream business and the capital we do spend on it, I believe we’ll get that back plus.

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

So 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 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 a round number of $7 million. So for $7 million we can keep 14% of that. We will let a lot of 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 acres something in that zip code, which is still plenty. We were talking – most of last year, we talked about 650,000 to 670,000. Again, into '15 we’ll be in the 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 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 than releasing it because it’s cheaper nowadays to release than when these leases were signed sometimes in 2010, '11 and '12. So in a lot of cases, you let it expire and you go release it for cheaper.

Thank you. That’s all from me. I appreciate it.

You’re 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 than 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 use as you’re probably hearing was below where the strip is right now. And the coverage we had from the PV-9 of our PDP, which is that’s how the banks calculate it, plus the value of our hedges. The coverage of that 900 million was 1.7x. 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 1.7x coverage that we had now on a price deck that’s below the strip, we feel very good about our borrowing base.

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

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 and the PUDs are 600 million, so not a big impact from the PUDs. That’s 2.7 and 600 in that. That is at our last 12 months of well costs, which is in the $3 million range. But 2.7 is I think the number you wanted.

That’s great. I appreciate that. And then you talked a little bit about the well declines by mix. Where do you estimate the current overall corporate decline and what did 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. They 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 halt the drilling altogether for the whole company, we’re on a 35% exit-to-exit decline, maybe kind of PDP decline based on everything we have on production at the start of the year.

That’s very good. Thank you. I appreciate it.

You’re welcome.

The next question comes from the line of Jamaal Dardar from TPH. Your line is open.

Hi. Good morning, guys.

Good morning.

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

Sure. We have not [indiscernible] for some time, they said they’ve been close. So we really don’t know what that means in IRS plan. So we’re kind of controlling the variables we can control. We’re keeping our S1 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 S1 active and we’ll see what happens with 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 kind of 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, it felt like Q4 well cost levels?

Yes. It was actually – kind of be 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 2s. So the full section development has gone very well. I would say on the full section development, that well IP close to 1,100 Boe per day and it’s 150-day cumes are 100% on oil in terms of 4x 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 on four single wells. And the long lateral was in a very good area with results well over a 1,000 barrels of oil per day.

Okay, great, sounds good. I guess just last thing from me. The Comanche, I see that there isn’t really any drilling directed there on the plant from your slides. Is that because of infrastructure?

It’s more so because of the GOR, very high gas in Comanche, at a different gas price. We kind of referred to it as potentially the gas bank but a different gas price. It could deliver some very strong gas rates. We’ve kind of 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 gassier area than it is liquids and oil.

Okay, great, sounds good. That’s all from 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 were asked before me, but wanted to ask a little bit on the capital structure. Specifically, the preferred units, those ones, are you able to defer the cash payments on those and sort of have it, I guess, accrete in principal value or do those cash payments need to be made?

No, we have a couple of options there. We could pick them for I believe it’s three quarters without any consequences, we cannot 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 at least a couple of those have some mandatory convertible features that you guys can exercise. What are your thoughts surrounding the exercise of those?

Well, a couple of things. There was one that mandatory converted in December. Remember, we had 765 million of preferreds, now it’s 567. So I think that’s the mandatory. Thinking about the others convert at a premium on their conversion price that’s the only way we could convert them and they’re pretty far of the money right now.

I thought that 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 I guess there’s two ways to go about it. One, you can invest in really high return projects and sort of have the company sort of earn its way out of its high leverage. The other way is to try to sort of cut back on the production and the investments to try to live within cash flows. How do you think about which are these two options preferable at this point in time?

Yes, exactly. At $90, it was the latter. We had 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 scale 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.

Okay, that’s great. 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 the options are, how do 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 don’t need to grow our cash generation ability on the assets we have or shrink our level of debt. Those are two options and I’ll just leave it at that. And that we’re very focused on liquidity and getting closer within cash flow and reducing our overall level to 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?

Going from 31 rigs down to seven and the CapEx budget going from 1.6 billion to 700, yes, we will have some working capital used 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.

If I look at your working capital, there’s a net balance of about 350. Is 350 a good number or is it much lower or is it – what’s the ballpark?

Yes, I don’t know. I’m not really read 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 costs, they’re going up in this environment. I’m just curious what’s the driver here?

Sure. It’s primarily growth in our use of ESPs or electric submersible pumps. In 2014, we had almost 100% use of ESPs. In 2013, that was about 60%. We went from in January 2014 400 ESPs. We ended the year at 900. We actually had a pretty big ESP conversion program. Gas with the ESPs about 185 we changed out. So what that does is greatly increase easier power consumption. Our power demand increased about 88% last year, so power is a big, big component of the LOE. And so we increased our power consumption 88% from 63 megawatts to about 118 megawatts, so that’s the lion’s share of it. So increased LOE but ESPs do create a lot of value. They give you higher production rates and they improve the abandonment pressure at the end of the wells, so improves your ultimate recovery. So it’s a good tradeoff.

Great. And then just last one for you just on the differential side. It looks like those are a little higher. Is that simply the fixed cost is a greater percentage of the prices or is there something going on in the fields?

No, we just need a transportation component, which doesn’t move as much when your commodity price moves.

Okay, 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.

Hi. Good morning, everybody. Thanks for taking my call. You mentioned that this $200 million of potential monetization 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?

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

Okay, got it. And I know you don’t want to give too much in the way of detail on the asset monetization, 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 sort of later in the year that 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 – make sure we get the right value for that and not rush to get anything done. But don’t expect anything right now.

Okay, great. And then lastly from me just your guidance and 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 but increased power. A couple of things. Our power consumption went up 88% year-over-year because of increased ESP. You roll that for a full year and you get a slight increase in LOE. That’s the primary driver.

All right, thank you.

You’re welcome.

The next question comes from the line of David 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 wells with 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 well results? Are they getting tighter in terms of hits and misses? Just any color there would be great.

Sure, Dave. Yes, you can imagine that for 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, 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 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, which you can see in our low finding costs of $9, 600% reserve replacement and adding over 140 million barrels, all that’s a function of drilling the right wells in the right spot for less dollars.

Great, I appreciate that. And then one other. 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 to make them more competitive and a redirection to capital?

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 carbon and 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 in the shale, it’s not as much of an option to leave it open hole, so you’d have a lot of cement, cemented liners, whipstock, things like that. So the multis are little more complicated in those two but longer laterals might be a better application there.

Great, I appreciate that. And one last one just to the LOE questions. 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’s one a little more inelastic. I will say on LOE it’s important for us to watch it and we have goals around it. It has a much smaller impact on our returns in PV than the upfront CapEx does. So when you got – LOE in the Miss is about $8, a 10% improvement in that only changes your IRR by a 100 basis points over the life of the well. So while impactful not nearly as impactful as the CapEx savings.

Okay. I really appreciate the added color guys. Thanks so much.

You’re welcome.

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

Hi. Thanks for taking the question. Just a follow up on the hedge book. Obviously, it dropped 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 best case plan, can you just elaborate a little bit about what your thoughts are on hedging and adding to the book?

Sure. We’re 10 million barrels hedged this year and about 4 million barrels of oil hedged in '16. It 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 the 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 un-hedged 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 just last question, just a clarification of a comment you made earlier with regards to the fourth quarter '14 compared to fourth quarter '15 exit rate, I think you said sort of mid teens. Was that for total production? And if that’s the case, would you expect that the decline on oil be greater than that or did I misunderstand and that was actually the decline for oil from '14 to '15?

No, I think you understood it correctly. That would be the total decline. So that would be on a Boe basis. And we’ve said that oil declines 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. I guess just a quick follow up is, and apologies if I missed this, on the IRR on the curve, you’ve shown the 45% to 40% IRR. I want to see what percentage of I guess 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. So 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. So, this is an average of our PUD program, so this would be close to what the 70% 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?

It would, because that EUR is for a PUD well, so the IP and 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 is commentary for junior debt up to $500 million. Just trying to understand what was the rational for that. And then is that senior to the bonds and just a little bit more detail on that carve-out?

Sure. So we have the ability to do, call it, junior lien debt, second lien debt, which would be senior to the bonds or 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 and 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 [ph]. Your line is open. If you’re on mute please un-mute your phone. Mr. Parr, your line is open.

We can go to the next caller, operator

Thank you. Your next question comes from the line of Shawn Needham from Oppenheimer. Your line is open.

Hi. Good morning, guys.

Good morning.

Maybe as a follow up to the last quarter there, James, as you kind of think about kind of 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 gives you optionality but as you said I think in your prepared remarks, you think 3.2 billion of debt is too much. So how you kind of think about what the appropriate capitalization in the business should be in the current environment?

At current commodity prices, so 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. 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 want to remove $1 billion of debt from the balance sheet. So we’ll come at it several different ways no longer try to grow the cash generation capability of the 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. With the world stabling as it was today, you’d probably want $1 billion less debt.

That makes sense. I guess would that be – 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 LINN. Are those things that you guys are considering in terms of reducing overall cash cost or cash CapEx for 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 and 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 then maybe just lastly from me for you, Eddie. I just wanted to clarify, so the – I guess you’re spending about 430 million in the Miss this year on CapEx and 600 or so on total EMP CapEx. Is it fair to assume the remaining portion of that is for the Permian, and I guess how much of that is going to be discretionary?

There’s no Permian spending this year. So that D&C that’s kind of roughly 450 million. 300 million of that’s 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 costs, watching all areas of spending, heightening in on the best areas of the play where we can generate consistent good returns and looking for ways to increase our cash flow and sure up the balance sheet. So know that you got a team of people here all focused on that and do the right things and create returns for the shareholders. Thank you all for your time.

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