SandRidge Energy Inc (SD) 2015 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to SandRidge Energy's first-quarter 2015 conference call. I would now like to 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 website under investor relations that we'll be referencing during the call. Keep in mind that today's call contains forward-looking statements and assumptions which are subject to risk and uncertainty, and actual results may differ materially from those projected in these forward-looking statements. Additionally, we will make reference to adjusted net income, adjusted EBITDA and other non-GAAP financial measures.

A reconciliation of the discussion of those measures can be found on our website and please note, 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.

Welcome everyone and thank you for joining us. I also want welcome Steve Turk to the call. Steve joined us in the first quarter as our COO and brings a depth of EMP, operating experience and leadership and we're 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. Second, discuss the balance sheet and how we're thinking about leverage and overall liability management in this market.

I am 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 costs continue to come down, our innovation efforts like multilaterals and long laterals are driving improved capital efficiency and as planned, we are reducing our recount in CapEx program.

Page 4 provides a good backdrop for how we're 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 mid-continent, and we are well on our way to $2.4 million per lateral costs.

Recall the year end, we increased our type curve by 27% to 484,000 barrels of oil equivalent. So, combining this lower costs and higher EUR our returns at the strip remain very competitive. This in turn, preserves and grows our mid-continent 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 are 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 are at one crew now.

As a result, at the end of the quarter we had 81 laterals in various stages of inventory. 30 IP rates were again about type curve, below oil and natural gas, exceeding 400 barrels of oil equivalent per day. Our multilateral 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 cost, our intense attention to well cost reduction is taking hold. Our cost per lateral are $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 cost, this gives us the 37% rate of return at the May 1 strip. At $2.4 million cost, with the same strip, the return is 50% which you can see on the graph on page 2.

If I include the cost of infrastructure, which averages about $220,000 per lateral, returns are about 10 percentage points 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 an active rig program at these return and cost levels.

In terms of pricing, we are budgeting for a $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 lower 70s levels, we'd likely look 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 front-end weighted this year. We exited 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 are continuing to get more efficient that system. In 2014 we spent $123 million on disposal wells and in their 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's 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 am focused on every day and it's 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 borrowing base of $900 million was reaffirmed in the spring, and in that redetermination, using bank pricing which is below the current strip, our proved developed reserves covered the borrowing base amount by 2.3 times. I mention this because this gives us confidence in maintaining this $900 million borrowing 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 2.5 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 said 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 1 strip, the PV-10 of that is $3.04 billion. Studying the market and our alternatives, our decision on 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've outlined on slide 7. We are a skilled, large-scale developer of mid-continent assets. We have over 1500 horizontal producing wells, have invested $5 billion in capital and produce almost 90,000 barrels of oil equivalent per day.

We have a large in-place power and water infrastructure system that we have been developing for many years and are getting more efficient with. These skillsets are transferable to other areas and other plays. We are an expert at horizontal redevelopment of legacy vertical fields and develop a deep understanding of mid-continent opportunities and 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 continuous improvements are part of our culture. We are the cost leader in the play, our per lateral costs $2.7 million, headed quickly to $2.4 million. We pioneered the use of multilaterals in the mid-continent and were the first to drill with horizontal Chester oil wells.

We have an active, appraisal new venture program, it's testing new zones and new concepts in the mid-continent, 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've said we're looking at many alternatives and nothing is off the table. It's a question of price while balancing liquidity and leverage.

And importantly, we are able to attract and retain top talent. Steve Turk recently joined us as COO, we're also pleased to welcome John Suter aboard, running operations, and also 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. Good morning. I am very pleased to participate in this quarter's call and I am excited to have joined SandRidge's leadership team. I have found the staff to be energized and fully committed to delivering on our plan. The teams delivered 101 laterals to sales, with a 30 day average IP of 402 barrels of oil equivalent per day, and 52% oil. That's 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 the 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 87,700 barrels of oil equivalent per day, down 1% from prior quarter and the mid-continent region averaged 76,200 barrels of oil per day, 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 to 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 a $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 well bore 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 reduced infrastructure investments during the year. This year we plan to drill one saltwater disposal well compared to 43 in 2014. And we are laying 50% less saltwater gathering pipe than in the prior year.

During the quarter, 77% of our wells drilled were designed for multiwell pads and 54% utilize shared tank battery facilities. I am pleased with the cost improvements thus far and look forward to sharing future updates on the team's 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 and 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 barrels of oil equivalent per day. That's 48% oil. Oil 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 are 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 will 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 in 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 of 2015 was 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 in MCO.

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, hedge settlements increased the blended Boe price by $17.35 to $42.14.

Our adjusted EBITDA was $182 million, or $23 of Boe for the first quarter of 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 2014, to $11.34 in Q1 2015. 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 had $713 million of availability under our $900 million borrowing base in our credit facility and $12 million of cash on hand. This liquidity position going forward is enhanced by our hedge 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 one 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. The 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 in March 31. For the remainder of 2015, at the midpoint of guidance, we have a 100% of oil hedge, 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 four 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 have updated guidance to lower the DD&A rate to account for the ceiling test write down for the first quarter, otherwise our guidance remained unchanged. Operator, that concludes my remarks, please open the call for questions.

(Operator Instructions)

Will Derek SunTrust

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

We showed in our prepared remarks, most of these savings we'll call durable savings, process improvements, efficiencies we mentioned, well re-designs, pad drilling, shared surface 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.

Okay great thanks. On the Chester, especially given the recent results, how much acreage right now to you all think is prospective for the Chester?

I don't think, Will, we've come out with the Chester, or even Woodford acre number yet. Look for us to get more clarity on that later in the year.

Okay. Thanks.

Kara Kamed, JPMorgan

Morning. Talked a lot about liability, a little bit about liability managing. Talk a little about potentials asset sales, I know there was an article in the local papers about potentially doing a sale lease back on the office building?

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

Secondly, in terms of timing on doing something on the balance sheet or liquidity side, any thoughts around that? Any minimum liquidity number that you would like to stay over as you go through the rest of this year?

You know we've got the $900 million available on our revolver and feel confident we will maintain that throughout this year, given that 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. No bond maturities until 2020, but I say time is on our side, but don't mistake that for a lack of action and sense of urgency. 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.

Got it. And then the last one for me working capital, any expectations for the remainder of this year, there was a big use this quarter, do you expect it to be used 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 in a negative working capital position, like a lot of EMP companies are, when you go from 35 rigs down to 7, that's a working capital use. And that was well over $100 million for the quarter and counts 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 ratably throughout the year. So we pay on a cash basis, most of our interest in dividends in the first quarter.

Got it. Thanks very much.

You're welcome.

Adam Lake, RBC Capital Markets

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

Yes, Adam, actually our PUDs are not that sensitive to economic cut off. I think the PUD value changed $100 million from the year end, the year to this current strip. They're not that sensitive, it's more PDT sensitivity. We do have some Permian Basin PUDs that will come back on the books, potentially as prices go higher, but the mid-continent they're not that sensitive to the economic cutoffs here. So we haven't had reserves really fall off the book much because of change in prices.

Is that a PV-10 to generate 10% MPVs at the strip?

Yes that's a PV-10, Adam.

Okay. And then on the balance sheet, potential restructuring, could you give us your thoughts on whether you're looking for a longer-term more 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?

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

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

That's it for me. Thanks.

Thank you Adam.

Sean Sneeden, Oppenheimer

Hi, good morning, thank you for taking the questions.

Maybe a follow-up on Adam's question there. Obviously you have highlighted that you are talking, thinking about different options in the balance sheet. Could you maybe help us understand the order of priority? I'm sure you have seen some of your peers undertake some debt for equity swaps as well as financing. Could you give us any sense, or any color of how you are thinking about those things? I know you highlighted price, which I assume you are talking about, price of order bonds are trading, where the equity is, any comments around that would be helpful.

Understand the question and the ask for clarity around that. You know we have a continuum of 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'm hesitant to give an exact order of our priorities here and what we're thinking of first versus last. Again price, liquidity, reducing leverage, you heard Adam ask as a longer solution, something you're interested. Yes, I think that's all the guidance I can give at this point, if you understand

Sure. I can appreciate that. Maybe in terms of timing, would you say at this point you are closer to launching one or any 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 the timing of any potential transaction.

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

Yes. We were encouraged with the proposed regulations that the IRS put out this week and believe that our saltwater gathering system would qualify under those regs 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 any more details on that business.

Great, I really appreciate it. Thank you.

Brian Kuzma, Kitco.

Good morning. Couple of questions for me. On the G&A front, do you seeing any substantial reductions between now and year end 2016?

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. The first quarter was higher this year. First quarter is usually higher on the payroll tax side, because you start accruing, you know, 401(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 the increase in the first quarter.

Our compensation plans have evolved to performance-based units and performance shares. Those are mark-to-market every quarter, so as the stock price goes up you are going to have more expense, as it goes down you're going to have less expense. With a contraction of stock price last year 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. In terms of guidance, we are still comfortable with the guidance range for this full year. But you will see some volatility quarter to quarter. You know we have had some sizable headcount reductions here in Oklahoma City, in the field reflective of a much lower activity level.

And remind me again, what is the actual cash G&A on an annualized basis?

Let me get the cash number. I believe it's $120 million. 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 things, 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 perpetuity. We will ramp back up at some point activity levels, given lower commodity prices, depending on where commodity prices are and our liquidity levels, but we don't anticipating staying at that activity level for years.

The $120 million in cash G&A right now, that is what is necessary to run a company that will do what? How many rigs can you run with that size company?

We could get close to the level, not the exact level we were, but we could run you know, mid-teens, 20 rigs. Steve's there telling me he thinks we could run 20 rigs, as well.

That begs the question, is that the right number then? Is it the plan to get back to 20 or is the plan -- does it make more sense to rightsize down to running low-teens or--?

It's going to 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 then we would certainly need to make adjustments. But don't infer that we are going back to a 20-rig program right now, just because we could.

Okay. And then another question for me. When you talk about liquidity being such a high priority. Like I look at you and I expect the liquidity situation seems pretty good and I understand you're looking out to 2016 and things don't look as good when you get out there. But I'm more curious about 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 are looking out certainly even past 2016, into 2017 and 2018 to make sure we are in a sound financial position. And depending on, you know mentioned going cash flow -- impact the cash flow going cash flow negative, it depends on the form of capital and the cost around it as to whether it impacts your cash flow negatively or not.

Okay. Okay and then finally on the Chester, you said you may expand that program. What's the highest percentage of rigs that you -- 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 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 program would shift to Chester, only because you want to get some consistent results over time 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 a rig at a time. I think that's part of our of our overall strategy, to diversify a little bit and develop these new plays.

All right. That's it for me. Thanks.

Okay, thank you.

Owen Douglas, Baird

Hello. Thanks for taking the question here, and I appreciate the great information that you gave on this call so far. 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 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, particularly in the first quarter could have a tendency to be higher. You'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 using a lot more electricity and that's one of the largest components of LOE. Look, as fuel prices come down, chemical prices come down, some efficiencies in the field, I think there's room there to improve that. I think there's bigger room to improve on the CapEx side, and that actually has a bigger impact on your return, so I think the most opportunities going to be on the well cost side. Yes, we do have some initiatives on the LOE side

Got you 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 bridge that delta a little bit?

Yes. $120 million was actually the total G&A, I misspoke. $100 million was 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. What are some of the items included, or the bigger items included in the G&A number? Looking at the consolidated company, while you guys are one of the more significant players, $100 million for year, I'm just going to imagine there will be some opportunity to take 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's the biggest component of that. There are also a couple other components that aren't obvious to people that cause it to be a little higher than it normally would be.

We do have four public reporting entities, including three other trusts, so we are responsible for all the costs 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.

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

I don't have that number in front of me. I think it is going to be much higher on the EMP side than that. You can call back in and we can give you more detail on that.

Got you, absolutely will do. Great. And what's the view with regards to drilling the oil field services business. You know, how does it stand firm from a regularization standpoint, and if you could help me understand better the longer term value of having that business and the midstream services business tied in with the EMP?

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 the big EMP company, EMP acquisition in 2007. And with 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.

Okay. Understood. Thanks very much. I'll hop back in the queue.

James Spicer, Wells Fargo

Hi, good morning.

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. 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. Understand the question. What we have said is you take the average rate for 2014, which was 75.700 thousand barrels of oil equivalent per day. To hold that level flat would be about $400 million, $375 million to $400 million of D&C CapEx. And year over year, we said that our exit to exit, 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 to hold production at that average for 2014 is in the neighborhood of $400 million of 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. 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.

Couple of things. Costs are coming down, so in that we assume about $2.5 million per lateral cost, with probably about 30% of the program being multilaterals. So costs coming down further will help that. Remember, we're only going to hit the $2.4 million cost in the back half of this year.

So costs coming down is one. And the PDP decline flattens over time. Our first year PDP decline, if you were to stop drilling, for the whole company is about 35%. And then about 25% and then about 15% with a little rounding in there. But the flattening of the PDP decline is a big component of that.

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

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

And about how much is that CapEx on a run rate basis?

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

Great, that's all very helpful. Thank you.

Brian Salvitti, Guggenheim

Thanks for the update call here. One question or two questions here. I don't know if I missed this. Did you state how many wells were drilled in the period and then how many were drilled and then completed?

Yes. It's in the earnings release: the number drilled is 116 laterals, rig released in the quarter. And then I believe 101 to first sales. And that compares to, if you look at the fourth quarter last year to 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 million versus $2.4 million goal. The question I had was, the $322 million of D&C CapEx, in the financials there's a $370 million something number on CapEx. What is the difference between the $322 million 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's a difference between, it's actually the cash flow statement and what your CapEx is for the quarter because you accrue some CapEx in the cash flow statement.

Okay. That's helpful. Thank you.

Adam Lake, RBC

I got my question answered. Thank you.

Jason Wangler, Wunderlich

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

No, I would say a couple things. We guided to lower oil. If you take the midpoint 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 down time 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.

Okay. And then you mentioned I think in the release, about the trust and 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.

Great. I'll turn it back.

(Operator Instructions)

Dave Kistler, Simmons and Company

Real quickly, yourselves and some of your peers have commented on the rates returned in the mix getting better, obviously well costs continuing to decline. When you think of liquidity options and rates return increasing has an appetite for assets within the mix picked up? Is there any market you're seeing for potentially divesting a portion of your asset base above and beyond the other items that you highlighted? Not to dip into the core, but potentially even look at monetizing part of the core as a source of liquidity?

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

You've seen other companies, you know, come out with drilling partnerships and other things. So I think there is a level of interest in the mid-continent. And you're right, you've seen other very good operators in the play come out with some positive news around the Miss. Just similar to us, well costs 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 a follow-up to that is, you know as you highlighted, more sort of base production versus virgin areas that have not been developed, 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 that it would be something probably more appropriate for dropping to an MLP, or how do you think about that in terms of fully developed versus partially undeveloped areas?

Sure. Low decline assets, particularly oily ones are as you know, suited for MLP. We haven't talk public about forming our own MLP or anything like that, but that's one option that we've looked at. Once you get a base of low decline assets that are producing many, many thousands of barrels of oil per day, I think that opens up a lot of options for other forms of capital that are lower cost to capital than us. MLPs are one, there are some others, as well. I think it's a big opportunity for us as that base of low decline, onshore, domestic oil for us gets bigger.

Okay. Appreciate that added color. Thanks.

Richard Tullis, Capital One Security

Good morning everyone, thank you.

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 $500 million or a $700 million budget?

I think we could continue at that level for quite some time. The team has done a good job of optimizing the system, making it bidirectional in many areas where we can flow water in either direction. Going back into areas where they capacity was full, going back in six months or a year later, now you have a lot more capacity, you don't have to drill on a disposal well.

So as we've 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 even 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 time.

That's all for me. Thanks, James.

Thank you.

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 of us continuing to execute. Our IP rates are strong, our results quarter to quarter are getting more consistent. We are executing the multilateral and long lateral program, finding new zones and the team does 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 are very proud of that. And as we've mentioned, we are actively paying attention to and looking at the balance sheet, figure out the way to bring the cash flow in line with our leverage levels. Thank you all for your questions.

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