Duane Grubert - EVP, IR and Strategy James Bennett - President and CEO Steve Turk - EVP and COO Eddie LeBlanc - EVP and CFO.

Will Derek - SunTrust Robinson Humphrey Tarek Hamid - JPMorgan Adam Leight - RBC Capital Markets Sean Sneeden - Oppenheimer & Company Owen Douglas - Robert W.

Baird James Spicer - Wells Fargo Securities Brian Salvitti - Guggenheim Securities Jason Wangler - Wunderlich Securities Dave Kistler - Simmons & Company Richard Tullis - Capital One Securities.

Ladies and gentlemen, thank you for standing by. Welcome to SandRidge Energy’s First Quarter 2015 Conference Call. I would like to now turn the call over to Mr. Duane Grubert, EVP of Investor Relations and Strategy..

Thank you, Operator. Welcome, everyone. 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, our President and Chief Executive Officer; Steve Turk, EVP and Chief Operating Officer and Eddie LeBlanc, EVP 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 the Web site. 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. Welcome, everyone and thanks for joining us. I also want to welcome Steve Turk to the call. Steve joined us in the first quarter as our COO and brings of depth of E&P operating experience and leadership and we are excited to have him on our team. I want to cover two main topics in my prepared remarks today.

First is an update on the quarter and the improvement initiatives that are taking hold. And second discuss the balance sheet and how we are thinking about leverage and overall liability management in this market. I'm pleased with our results in the first quarter as our teams are executing operationally.

Turning to Slide 3 in the presentation we posted this morning, we hit all components of our guidance and delivered adjusted EBITDA of 182 million. Well cost continue to come down, our innovation efforts like multilaterals and long laterals are driving improved capital efficiency and as planned we are reducing our rig count and CapEx program.

Page 4 provides a good backdrop for how we are approaching 2015. Lower well costs, consistency and scale are key differentiators in this play. Our well costs are coming down every quarter and every year in the Midcontinent, and we are well on our way to 2.4 million per lateral cost.

Recall at year-end we increased our type curve by 27% to 484,000 barrels of oil equivalent. So, combining these lower costs and higher EUR our returns at the strip remain very competitive. This in turn preserves and grows our Midcontinent location inventory.

For the quarter production was in line with expectations and a product of our planned activity ramp down from 35 rigs at year-end to 13 rigs at the end of the first quarter. As part of our focus on maximizing returns and capital discipline we’re being selective in terms of putting new wells online.

For example we are deferring connecting wells with exceptions like water hauling or generator rentals. We also ramped down our frac crews to two during the quarter and have one crew now. As a result at the end of the quarter we had 81 laterals in various stages of inventory.

30-day IP fee rates were again above type curve for both oil and natural gas, exceeding 400 barrels of oil equivalent per day. Our multi-lateral initiative continues to meet or exceed expectations and will become a larger percentage of our drilling in the remainder of 2015.

In terms of performance for the entire program, for the 47 multilaterals online for at least 90 days, the 90 day cumulative production is averaging just over 100% of our Mississippian type curve.

Turning to costs, our intense attention to well cost reduction is taking hold, our cost per lateral are at 2.7 million down 10% from 2014 and we have line of sight to achieving 2.4 million in the back half of this year.

Steve will provide greater detail but these cost improvements come from service cost reductions, efficiency gain and increased use of multilaterals. A very important part of the effort and the largest component of the program are capturing durable cost improvements that will last through any commodity price cycle.

Things like cycle time reductions, well redesign, co-mingled surface facilities and increased use of pad drilling as a few examples. At current 2.7 million costs, this gives us a 37% rate of return at the May 1st strip at 2.4 million costs with the same strip the return is 50% which you can see on the graph on Page 2.

While including the cost of infrastructure which averages about 220,000 per lateral returns are about 10 percentage point lower.

So, in summary with our 2.4 million well costs using our updated type curve and including saltwater gathering costs we are still at a very competitive 40% rate of return and we can maintain that active rate program at these return and cost levels. In terms of pricing we're budgeting for $55 oil market for the next 18 months.

However given the returns we are seeing at these lower well costs if oil were to strengthen into the low 70s levels we are likely ought to begin hedging there and even start to think about a measured increase in activity levels.

On capital expenditures we spent 322 million in the first quarter a 45% of our full year budget as our program is always fronted end weighted this year. We exit 2014 at 35 rigs averaged 24 for the quarter and are at 7 now. Turning to Slide 5, you can see where these rigs are operating.

We have development rigs in four counties in Oklahoma and Kansas and one new venture rig that is testing concepts outside of our focus area. In terms of our water gathering infrastructure CapEx, we’re continuing to get more efficient with that system. In 2014 we spent 143 million on disposal well and in our associated pipeline infrastructure.

In 2015, we will spend approximately 38 million or 70% less and we will have reduced our gross per lateral disposal capital cost down to $220,000. Overall total CapEx will continue to come down each quarter, reflecting the slower rig count and continued cost reductions.

We will be at 100 million CapEx per quarter or 400 million annual run rate in the fourth quarter of this year. Turning to our balance sheet, it is no surprise that given market conditions leverage, liquidity and overall balance sheet health are a very big topic with investors and stakeholders.

This is something that I'm focused on everyday and it is an area where I and other members of our team have a lot of prior experience. First we have to be most focused on liquidity.

As shown on Slide 6 at quarter end we had 725 million of liquidity, our volume base of 900 million was reaffirmed in the spring and in that redetermination using bank pricing which is below the curve strip our crude developed reserves covered the volume base amount by 2.3 times.

I mentioned this because this gives us confidence in maintaining this 900 million volume base in our fall redetermination. Also supportive of our liquidity and leverage we plan to monetize about 200 million through asset sales this year.

Our covenants were revised earlier this year to 2.25 senior secured tests our senior secured leverage ratio is 0.2 right now and total leverage is approximately 4 times. Also recall we have no bond maturities until 2020.

We are actively considering many alternatives to reduce total debt as I have in the past we want to align our debt levels with the cash generation capability of our assets. There are many different ways to get there and we haven’t ruled out any alternative and are proactive on multiple fronts.

We do have a unique capital structure with only 5% of our funded debt as senior secured on top of the large asset base just for frame of reference if you take our year-end reserves with no new bookings for our year-to-date activities. At the May 1st strip the PV-10 of that is 3.04 billion.

Studying the market and our alternatives our decision are what exactly we would do, will be around price while balancing liquidity and leverage. Let me summarize and take a step back and explain our strengths as I have outlined one on Slide 7. We are skilled large scale developer of Midcontinent assets.

We have over 1,500 horizontal producing wells have invested 5 billion in capital and produced almost 90,000 barrels of oil equivalent per day. We have the large in place power and water infrastructure system that we've been developing for many years and getting more efficient with. These skill sets are transferable to other areas and other plays.

We are an expert at horizontal redevelopment of legacy vertical fields and developed a deep understanding of Midcontinent opportunities in the geology. We have a large capacity to execute at the peak we ran 35 horizontal rigs and averaged 31 rigs in 2014 so we can efficiently run a large scale program.

Innovation and continues improvements are part of our culture. We are the cost leader in the play our per-lateral costs are 2.7 million headed quickly to 2.4 million. We pioneered the use the multilaterals in the Midcontinent and were the first to drill horizontal Chester oil wells.

We have an active appraisal in new venture program it is testing new zones and new concepts in the Midcontinent and importantly we have a strong team with experience from majors, independents, midstream and Wall Street.

We do have options to reduce debt as I said we are looking at many alternatives and nothing is off the table it is a question of price while balancing liquidity and leverage. And importantly we’re able to attract and retain top talent.

Steve Turk recently joined as COO, we are also pleased to welcome John Suter aboard running operations and I also remind that Kevin Clement joined us in the fourth quarter to run our midstream and saltwater gathering business. With that let me turn the call over to Steve Turk..

Thank you, James and good morning. I'm very pleased to participate in this quarter’s call and I'm excited to have joined SandRidge's leadership team. I found the staff to be energized and fully committed to delivering on our plan.

The team’s delivered 101 laterals to sales with a 30-day average IP of 402 barrels of oil equivalent per day and 52% oil that is 115% of our type curve. We also rapidly reduced rig count from 35 rigs exiting 2014 to 13 rigs at quarter-end.

We achieved our current seven rig run rate at end of April and we plan to maintain this level of activity for the remainder of the year.

Total company production for the quarter averaged 877,000 barrels of oil equivalent per day down 1% from prior quarter and the mid-con region averaged 762,000 barrels of oil equivalent per day to down 2% from the prior quarter.

Due to a significant focus on capital discipline we are managing the timing of oil connects to avoid the high cost of trucking water and running generators and have opted to reduce the number of dedicated frac crews to one crew.

Production impacts by these strategic well connect practices are offset by a strong well set in the quarter and will not affect our ability to meet production guidance for the year.

Given my experience with quickly aligning cost structures with commodity price fluctuations, I joined the team with immediate focus on reducing drilling, completion and infrastructure expenditures.

I would like to share the results of several cost reduction initiatives currently underway which drive us towards our goal of $2.4 million per lateral in the second half of the year. As depicted on Slide 9 of the presentation we have already achieved a $350,000 decrease in well costs or 58% of our $600,000 cost reduction target during the quarter.

Re-bidding services and materials resulted in $200,000 in savings to-date. We also have specialized technical teams focused on identifying long-term sustainable reductions.

Through drilling and completion innovations such as wellbore redesign and stimulation enhancements their efforts have already reduced cost by about $130,000 and as shown on Slide 10 spud to rig release cycle times were shortened by 30% from 20 days at year-end 2014 to 14 days at quarter-end.

Additionally strategic location selection and utilizing shared facilities will significantly reduce infrastructure investments during the year. This year we plan to drill one salt water disposal well compared to 43 in 2014 and we are laying 50% less salt water gathering pipe than in the prior year.

During the quarter 77% of our wells drilled were designed from multi well pads and 54% utilized shared tank battery facilities. I’m pleased with the cost improvements thus far and look forward to sharing future updates on the teams’ continued progress.

Ongoing successful multilateral expansion across five counties contributed to 30% of the quarter one drilling program with an average per lateral cost of $2.5 million. The 33 laterals that were drilled using multilateral design and that were connected in quarter one averaged 383 barrels of oil equivalent per day or 109% of our type curve.

We are now extending multilateral development by applying internal expertise to two mile long laterals with initial encouraging results. With continued success we expect 40% to 50% lateral delivery from multilateral drilling during the remainder of the year.

Play diversification continues to be a focus with one rig line dedicated to appraisal drilling in non-Mississippian targeting. Completed analysis of acquired 3D seismic data will assist with future location selection and our current acreage position offers plenty of running room for program expansion.

In addition we are continuing the initial phase of Woodford and Chester development. During the quarter six Chester wells went to sales with an average 30-day IP of 452,000 barrels of oil equivalent per day that’s 48% oil.

Well cost reduction efforts and recent well design changes are bringing Chester drilling and completion cost in line with Mississippian standard laterals. Additionally lower water production requires lower infrastructure investment. We are extremely excited about the Chester.

We currently have one rig dedicated to Chester development and are evaluating the expansion of this program during the second half. In addition three new Woodford wells were brought to sales with an average 30-day IP of 199 barrels of oil equivalent per day that was 79% oil.

In conclusion, we’re making significant progress towards meeting our cost reduction goals while continuing to be innovative and to explore new opportunities to expand our Miss play as well as our new Woodford and Chester prospects.

I would like to thank our teams for their commitment to safety and to preserving capital as we continuously strive to become more efficient. I’ll now turn the call over to Eddie LeBlanc our CFO..

Thanks Steve, and thank you all for joining our first quarter call. I will be describing information for adjusted EBITDA, production volumes, product prices and items illustrated on our income statement and our pro forma amounts for the first quarter of 2014. Pro forma amounts are adjusted for the divestiture of the Gulf assets in February last year.

Production for the first quarter 2015 is 7.9 million barrels of oil equivalent, a 36% increase over the same quarter in 2014. Realized product pricing for the first quarter 2015 for oil declined 53% to $45.35 a barrel. NGL pricing declined 66% to $14.71 per barrel and natural gas declined 46% to $2.38 an Mcf.

Recall that we have a very robust hedge position and our 2015 hedges have provided and will continue to provide us with increased revenue into 2016. For the first quarter hedged settlements increased the blended Boe price by $17.35 to $42.14.

Our adjusted EBITDA was $182 million or $23 a Boe for the first quarter 2015 compared to $169 million or $29 a barrel for the first quarter 2014.

This $13 million increase is primarily due to $172 million of decreased revenue from price declines which was partly offset by $52 million of revenue generated by the increased production, yielding a net $120 million decrease in production revenue.

More than offsetting the decline in production revenue is $150 million increased benefit from hedge settlements. Additionally, lease operating expenses declined on a per barrel basis from $12.40 in Q1 ’14 to $11.34 in Q1 ’15. Due to the decline in product prices, we recorded a non-cash ceiling test write down of $1.1 billion in the first quarter.

As is illustrated on Slide 6 we closed the quarter with liquidity of $725 million.

We have $713 million of availability under our $900 million borrowing base and our credit facility and $12 million of cash on-hand this liquidity position going forward is enhanced by our hedged position and allows us to select the right liquidity management option for the company at favorable pricing.

Capital expenditures during the quarter were $322 million representing 46% of our 2015 front-end loaded capital expenditure plan. We expect continued declines in capital expenditures quarterly, as we ramp down our rig count to finish the year on plan at $700 million the fourth quarter is expected to be at a rate of $400 million annual rate.

Our debt of 3.4 billion at quarter end was comprised of $175 million of senior secured debt under the credit facility and $3.2 billion of senior notes. This first senior note maturity is in 2020. The senior secured leverage ratio was 0.22 times as compared to our maximum bank covenant ratio of 2.25 times.

With regards to hedging our mark-to-market position was a positive $251 million at March 31st. For the remainder of 2015 at the midpoint of guidance we have a 100% of oil hedged, 46% of which is hedged at an average swap price of $92.25 and 54% is hedged under three-way collars with an average of $13.50 as a price added to WTI for settlement pricing.

For 2016 4 million barrels of oil are hedged with 36% in swaps at a price of $88.36 and 64% are three-way collars, with an average of $6.86 as a price added to WTI.

As noted in the shareholder update and earnings release, we've updated guidance to lower the DD&A rate to account for the ceiling test write down for the first quarter, otherwise our guidance remains unchanged. Operator that concludes my remarks, please open the call for questions..

[Operator Instructions] Your first question comes from the line of Will Derek of SunTrust. Your line is open..

On the cost side, James, talking about reductions getting down to maybe 2.4 million to 2.5 million bucks on your wells, what sort of sensitivity do you all expect this to have with oil prices going forward?.

Well what we said in our prepared remarks most of these savings are what we call durable savings, process improvements, efficiencies we mentioned improved, well redesigns pad drilling, shared service facilities and increased use of multilaterals.

So our intention is that more than half of these savings will be durable and survive in even a rising commodity price environment..

On the Chester, especially given the recent results, how much acreage right now do you all think is perspective for the Chester?.

I don’t think we would come out with the Chester or even a Woodford acreage number yet, look for us to give more clarity on that later in the year..

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

You talked a lot about liability, a little bit about liability management talk a little about some of the potential asset sales.

I know there was an article in the local papers about potentially doing a sale lease back on the office building?.

Yes. We've mentioned several things in terms of options to monetize assets we have some real estate holdings, we have some smaller non-core E&P properties we have some infrastructure whether it's a water gathering or electrical or another other infrastructure those would be the potential sources of monetizations this year..

And then just secondly, in terms of timing on sort of doing something on the balance sheet or liquidity side kind of any thoughts around that, any minimum liquidity number that you guys would like to stay over as you go through the rest of this year?.

We’ve got the 900 million available in the revolver and feel confident we’ll maintain that throughout this year given the asset coverage we have under there. With these planned liquidity enhancers, call it asset sales and monetizations, we have no liquidity pressures this year and then well into next year. So the time is on our side here.

Again no bond maturities until 2020 but I think time is on our side but don’t mistake that for a lack of action and sense of urgency. So we do want to get something done I don’t want to layout a specific timeline but this is a very high priority for us..

And then one last one for me, it is on working capital, any expectations for the remainder of this year it was a big use this quarter, do you expect it to be a use for the rest of the year or likely neutral?.

Likely neutral, it was a big use in the first quarter as we expected.

When you go from when you are at a negative working capital position like the lot of E&P companies are, when you go from 35 rigs down to seven that’s a working capital use and that was well over $100 million for the quarter and it accounts for a large portion of the cash burn for the quarter.

I’ll also note that the first quarter is one of our heaviest in terms of interest expense and dividends those aren’t addable throughout the year. So we pay on a cash basis, most of our interest and dividends in the first quarter..

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

You mentioned PV-10 strip for improved reserves, can you give us an idea of how much of your PUDs may not be economic at the strip and kind of what might the addable if prices continue to rise, and what are the price points where reserves would come back on the books, forgetting about the well plan issues?.

Yes Adam, actually our PUDs are not that sensitive to economic cut-off. I think the PUD value changed to $100 million from the year-end to this current strip. So they are not that sensitive it’s more PDP sensitivity.

We do have some Permian Basin PUDs that will come back on the books so potentially as prices go higher but in the Midcontinent they are not that sensitive to the economic cut-offs. So we haven’t had reserves really fall to book much because of change in prices..

Is that a PV-10 [indiscernible] generate 10% MPVs at the strip or?.

Yes, that’s a PV-10, Adam..

And then on the balance sheet, potential restructuring, could you just give us your thoughts on whether you’re looking for a longer-term or permanent fix to the balance sheet versus just creating more flexibility in the intermediate term.

And just going back to what you said on the fourth quarter call about thinking $1 billion reduction in debt would be appropriate at then current pricing, how are you thinking about that today in that context?.

So, on the first part, would we like to enhance our flexibility or provide a longer term solution? I’ll say yes, to both of those. It will be dependent on price and what the market will allow and where various things are pricing in the market.

So yes, to both of those I did say that liquidity is paramount in our business so that’s maybe priority number one but longer term solution and getting our cash flow in line with our debt is very important and if you do the math on the spread sheet the debt reduction probably needs to be in that $1 billion range or a substantial increase in the cash flow..

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

Maybe to follow-up on Adam’s question there, obviously you guys have highlighted that you are talking or thinking about different options in the balance sheet, could you maybe help us to kind of understand the order of priority.

I’m sure you guys have seen some of your peers undertake some debt for equity swaps as well as second lien financing so could you give us any sense or any color of how you guys are thinking about those things? I know you kind of highlighted price, which I assume you are talking about, price of where your bonds are trading, where the equity is, or any kind of comments around that would be helpful?.

Yes, I understand the question and the ask for clarity around that we have a continuum options we’re looking at, those change as market conditions change and pricing moves around and opportunities become available. I’m hesitant to comment on the order of those because as soon as I do whatever I list as number one just got 25% more expensive.

So I am hesitant to give an exact order of our priorities here and what we’re thinking about first versus last but again price liquidity reducing leverage you heard Adam ask is a longer term solution something you are interested. Yes, I think that’s probably all the guidance I can give at this point if you understand..

Sure. I can appreciate that.

Maybe in terms of the timing would you say at this point you are closer to launching one or many of your initiatives than you were say on the fourth quarter call?.

No, not to be dodgy but for the same reason I can't really comment on timing of any potential transaction..

Maybe just lastly on the saltwater monetization, it would appear that some of the proposed IRS rulings would be relatively favorable for potential formation of a MLP for your guys.

Is that guys how you're thinking about it for this year and is it still kind of on-track to hopefully launch late for the year?.

Yes we are encouraged with the proposed regulations that the IRS put out this week and believe that our saltwater gathering system would qualify under those ranks as drafted keep in mind that those are preliminary and subject to public comment I think that ends around August 4, but I think with the direction that's going we feel good about our chances to receive a PLR, I'll refer you to the S-1 that is on file for a more details on that business..

Your next question comes from the line of [Brian Kuzma] of [Kitcom]. Your line is open..

A couple of questions for me, on the G&A front, do you guys see any substantial reductions between now and say year-end ’16?.

So we've given G&A guidance and if you look at our quarterly G&A it does bounce around a bit that's for a couple of reasons and the first quarter was higher this year first quarter is usually higher on the payroll tax side because you start accruing 41-K and payroll taxes so that was 1.5 million higher we did have higher legal bills in the first quarter and some consulting bills so that was increased in the first quarter, but our compensation plans have evolved to performance based units and performance shares those are kind of mark-to-market every quarter so as the stock price goes up you are going to have more expense as it goes down you are going to have less expense with the contraction of stock price and so we actually had kind of negative G&A from those as you write them down so we will experience some volatility in our G&A from quarter-to-quarter for compensation but in terms of guidance we’re still comfortable with the guidance range for this full year but you will see some volatility quarter-to-quarter and we have had some sizeable headcount reductions here in Oklahoma city in the field reflective of a much lower activity level..

And then remind me again, what is the actual just cash G&A on an annualized basis right now?.

Let me get the cash number I believe it's 120 million but is that right 120 million..

I guess my question is, if you are at 120 million and you get down to that 100 million a quarter type of CapEx run rate that seems a little misaligned relative to the peers?.

Sure, a couple of things here we made some adjustments in headcounts earlier this year.

I don’t anticipate us staying at 100 million or 400 million annual run rate into in the perpetuity we will ramp back up at some point activity levels given where commodity price is depending on where commodity prices are and our liquidity levels but we don’t anticipate staying at that activity level for years..

But the 120 million in cash G&A right now like that is what is necessary to run a company that will do what like that is -- how many rigs can you run with that size company?.

We could get closer to level not the exactly level where we were but we could run mid-teens 20 rigs. Steve there is telling me he thinks we could run 20 rigs as well..

Yes..

And I guess that bags the question of like is that the right number then? I guess is the plan to get back to 20 or is the plan or does it make more sense to right size down to running low-teens or?.

It's going to be depend on what the market looks like looking forward to $50 flat oil environment for many years it might make sense to run at 100 million a year or 400 million a year CapEx plan if that's the case and we would certainly need to make adjustments but don't infer that we’re going back to a 20 rig program right now just because we could..

And then another question for me, when you talk about liquidity being such a high priority like I look at you guys and I still think the liquidity situation seems pretty good and I understand when you're looking out to ’16 and things don't look as good when you get out there.

But I'm more curious about like some of the stuff that's been floated out around sale leaseback and stuff like that, and I just wonder the optics of that, how they flow through your financials. And it looks to me if you do something like that it would take your cash flow negative, if you did some sort of significant financing.

And I just think optically that's something that you want to avoid?.

Well we’re looking out certainly even past ’16, call into ’17 and ’18 to make sure we are in a sound financial position and depending on I mentioned going cash flow, impact the cash flow and cash flow negative it depends on the form of capital and the cost around it whether it impacts your cash flow negatively or not..

And then finally on the Chester, you said you may expand that program.

What’s the highest percentage of rigs that you guys -- let’s say this keeps delivering better results than the Miss, do you put two-thirds of your rigs in the Chester program, or that just probably won’t ever happen?.

This is Steve Turk.

I think it’s a little bit early to sit here and quantify what percentage of the programs would shift to Chester only because we want to get some consistent results overtime before you make large commitments I think we would look at it from the standpoint as we have success in the Chester we would ramp-up the rig at a time I think that’s part of our overall strategy to diversify a little bit and develop these new plays..

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

I was hoping to better understand a little bit on the operational cost side, just so as I think about the LOE, and you know, any further prospects you guys could have for reducing that number.

I kind of noted that we saw a slight uptick in the proportion of gas relative to the fourth-quarter production, but at the same time the LOE number on a unit basis seem to tick up.

Can you help me understand that a little better and understand where that is going to be going?.

Sure. LOE on a quarterly basis which would be in the first quarter can have a tendency to be higher. And we’ve got a lot of winter weather use of methanol and chemicals in the field.

So first quarter is usually one of our higher LOE quarters also as we have increased our use of ESPs we’re using a lot more electricity and that’s one of the larger components of LOE. But look as fuel prices come down chemical prices come down, some efficiencies in the field I think there is room there to improve that.

I think there is bigger room to improve on the CapEx side and that actually has a bigger impact on your return. So I think the most opportunity is going to be on the well cost side but yes, we do have some initiatives on the LOE side..

And not to belabor the point, but jumping back to the cash G&A, so I believe that the numbers that you were recently providing to the previous caller, sort of guided to the midpoint roughly $4, $4.10 of cash G&A for the year on a Boe basis, just looking at the midpoint of your production guidance.

Versus looking at the slide presentation, where it was guided more to that lower $3 range to the cash G&A number.

Can you help me sort of bridge that delta a little bit?.

Yes, the 120 was actually the total G&A I misspoke 100 the cash. So 100 million of cash G&A and 20 million of stock G&A..

So that’s how you get to that low $3 range number.

And what are some of the items that included, or the bigger items included in the G&A number? Just because looking at the consolidated company, while you guys are one of the more significant players, $100 million a year, I’m just going to imagine there will be some opportunity to tick that further down?.

Yes, and keep in mind it was about 210 million two years ago just for a frame of reference but payroll and compensation and employee headcount is biggest component of that. And then also a couple of other components that are obvious to people that caused it to be a little higher than it normally would be.

We do have four public reporting entities including three other trusts so responsible for all the cost and filing fees, audit tax preparation around those other three entities. So that has an impact on it as well that may not be obvious to a lot of people.

But again $100 million we have taken it down from over 200 million and we look at G&A improvement initiatives every quarter..

And we understand the drilling and oil field services business and the midstream businesses, lumping those two together, if you would for a second versus the E&P business, what would be the rough breakdown in the G&A basis between the E&P and these other businesses? Is it roughly 60-40, with 60% being going to the E&P segment?.

I don’t have that number in front of me I think it could be much higher on the E&P side than that but I don’t have those numbers right in front. You can call back and we give you some more detail on that..

And what’s the view with regards to drilling in the oil field services business.

How does it stand from a rig utilization standpoint, and just if you could help me understand better the kind of longer term value of having that business and the midstream services business tied in with the E&P?.

So the midstream is largely our electrical infrastructure and some gathering infrastructure on the services business half the rigs we’re running right now are our own Lariat rigs so it does provide us some flexibility but this was a business that was acquired with a big E&P company and the E&P acquisition in 2007 and look longer term I don’t know that we need to be in the rig business long-term but I think right now is not a time where you would market a business like that..

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

Just wanted to try to get a little more clarification around CapEx and maintenance CapEx, obviously it's been a pretty big topic of discussion for you guys. Understanding that the spend is declining towards that $100 million quarterly run rate in the back half of the year, and the production I believe is still declining over that period.

You know, you also indicated you could probably hold production flat going forward at that level of spend, just wondering what assumptions you are making there in terms of additional cost reductions, the plan rates or anything else?.

Sure, I understand the question. What we've said is that, if you take the average our average rate for 2014 which was 757,000 barrels of oil equivalent per day. To hold that level flat would be about 375 million to 400 million of D&C CapEx.

And year-over-year we said that our exit-to-exit kind of quarter-to-quarter is going to be a mid-teens decline from our 88,000 barrels a day level at the end of 2014.

So, again mid-teens year-over-year decline but the whole production at the average for 2014 is in the neighborhood of 400 million to D&C and then you would have to make a decision on top of that how much do you spend on land and any appraisal, new venture program on top of that so you could go bare bones and spend none or if you spend some amount of money on land and appraisal and other infrastructure, does that answer your question?.

Yes, yes.

I guess I am if you are still, if production is still declining in the back half of the year, at that with $100 million capital spend, and roughly that 75,000 barrel a day run rate, what changes in the production profile such that, that same amount of capital can begin to hold the production flat?.

Yes, a couple of things costs are coming down so in that we assume about a $2.5 million per lateral cost with probably about 30% of the program being multilaterals so cost coming down further will help that remember when we are going to hit this 2.4 million cost in the back half of this year so cost coming down is one and the PDP decline flattens overtime our first year PDP decline if you were to stop drilling for the while company is about 35% and then about 25% and then about 15% with the little rounding in there but the flattening of the PDP decline is a big component of that..

And then is the saltwater disposal or infrastructure, that's not part of that D&C CapEx right?.

No it's not that would be just drilling and completing the wells. That would not be part of that..

And about how much is that CapEx on a sort of the run rate basis?.

Probably at that level it would be 30 million a year..

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

I guess just one question or two questions here. I don't know if I missed this.

Did you guys state how many wells were drilled in the period and then how many were drilled and then completed?.

Yes, so in our earnings release the number of drilled is 116 laterals rig released in the quarter and then I believe the 101 to first sales. And that compares to if you look at the fourth quarter last year the first sales we had 128..

Okay that's helpful on the completion side. And I think the other follow-up is, you obviously highlighted your well completion costs down closer to 2.7 versus 2.4 of goal. I guess the question I had was, the 322 of D&C CapEx, in the financials and I think there's a 370 something number on CapEx.

What is the difference between the 322 in CapEx that you state and the larger number in your financials?.

I believe that’s the cash flow, you’re talking about the cash flow statement. So there is difference between -- it’s actually the cash flow statement and what your CapEx is for the quarter, could you accrue some CapEx in the cash flow statement..

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

Yes I got my question answered. Thank you..

Thanks Adam..

Your next question comes from Jason Wangler of Wunderlich. Your line is open..

I was just curious on the production, the oil looked like it kind of came down a bit in the first quarter, was there anything that happened there? Because obviously you reiterated guidance, so still kind of trending towards the number, but it kind of came off a little bit more than commodities in the first quarter?.

No, obviously a couple of things, we guide to lower oil. If you take the mid-point of our guidance it’s oil down 7% year-over-year. So I think this is largely consistent with that. We did have some outages and downtime in the Permian which is all oil just associated with some weather out there in the first quarter.

But this is in line with guidance and what we had expected on a quarterly basis..

And then you mentioned I think in the release, about the trust and kind of being done with that, those obligations.

Is there an ability to use those vehicles as something you can monetize as well, or is that something you are looking at?.

Yes, that is something we are looking at. We can sell the trust units and particularly the common units, any of the public market or private transactions. But yes, that’s one of the alternatives on our list..

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

Real quickly, I mean yourselves and some of your peers have commented on the rates returned in the Miss getting better, obviously well cost continuing to decline.

When you think of liquidity options and rates of return increasing has an appetite for, I guess, assets within the Miss pick up? Is there any sort of market you’re seeing for potentially divesting a portion of your asset base above and beyond the other items that you highlighted? So, not to dip into the core but potentially even look at monetizing part of the core is a source of liquidity?.

Yes David, that’s certainly an option particularly as we get a bigger well set. We have 1,500 producing horizontal wells now some of those are very mature and on a flatter decline. So yes, there are things you can do around a big base of PDP assets or undeveloped assets.

You’re seeing other companies come out with drilling partnerships and other things.

So I think there is a level of interest in the Midcontinent and you are right you have seen other very good operators in the play come out with some positive news around the Miss, just similar to us well cost coming down, results being more consistent quarter-to-quarter.

So I think people are doing us and others a good job of understanding how to do large scale development in the Miss. But yes, pieces of the asset base are certainly options for us in terms of ways to raise some capital..

And I guess a follow-up to that is, as you highlighted, more sort of base production versus I guess virgin areas that have not been developed just because obviously there is a capital intensity towards putting in the infrastructure et cetera there.

Does that mean, or as you look at this, does that mean it would be something probably more appropriate for dropping to an MLP, or how do you think about that in terms of, I guess fully developed versus partially undeveloped areas?.

Sure. Low defined assets particularly oily ones are as you know suited for MLP.

We haven’t talked public about forming our own MLP or anything like that, but that’s one option that we have look at it once we get a big base of low decline assets that are producing many, many thousands barrels of oil a day I think that opens up a lot of options for other forms of capital that are lower cost of capital than us.

MLPs are one, there are some others as well, so I think it’s a big opportunity for us as that base of low decline onshore domestic oil for us gets bigger..

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

Just a quick question, you referenced the saltwater disposal spending expectations associated with $375 million, $400 million CapEx budget of around 30 million. How long could you continue to spend at that level? A lot of that has to do with drilling in more developed areas, as I understand it.

How long can you continue at that level before you would have to start ramping up the infrastructure spending or what would be the relationship say if you were at a 5 or a $700 million budget?.

I think we could continue at that level for quite some time.

The team’s done a very good job of optimizing the system making it bidirectional in many areas where we can flow water either direction going back into areas where the capacity was full going back in six months a year later now you have a lot more capacity you don’t have to drill enough disposal well so as we slow down our activity level we've been able to optimize the system to a greater extent than probably we even thought we could one or two years ago also as we drill in some of these areas like the Chester with much less water requirements where you can truck the water and don’t need a disposal system I think you will see that number as a percent of the total spend continue to come down so I think we could maintain that level or lower for a long period of time..

There are no further questions at this time. I'll turn the call back over to the presenters..

Thank you, thank you for the questions everyone. I believe the first quarter is evident us continuing to execute our IP rates are strong, our results quarter-to-quarter getting more consistent.

We are executing the multilateral and long lateral program finding new zones and the teams have done a great job of continuing to innovate whether it's multilaterals, efficient use of our water gathering system or continuing to drive the cost down the team continues to execute on that every quarter and we’re very proud of that and as we've mentioned we are actively paying attention to and looking at the balance sheet so we got the right way to bring the cash flow in line with our leverage levels.

Well, thank you all for your questions..

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