Duane M. Grubert - Executive VP-Investor Relations & Strategy James D. Bennett - President, Chief Executive Officer & Director Steve Turk - Chief Operating Officer & Executive Vice President Julian Mark Bott - Chief Financial Officer & Executive VP.

Will C. Derrick - SunTrust Robinson Humphrey, Inc. Adam Leight - RBC Capital Markets LLC Charles A. Meade - Johnson Rice & Co. LLC Tarek Hamid - JPMorgan Securities LLC Amer Tiwana - CRT Capital Group LLC James A. Spicer - Wells Fargo Securities LLC Joshua Gale - GMP Securities LLC Steven Marc Karpel - Credit Suisse Securities (USA) LLC (Broker) Sean M.

Sneeden - Oppenheimer & Co., Inc. (Broker) Gregg Brody - Bank of America Merrill Lynch.

Ladies and gentlemen, thank you for standing by. Welcome to SandRidge Energy's Third Quarter 2015 Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. Thank you. I would now like to turn the call over to Mr.

Duane Grubert, Executive Vice President of Investor Relations and Strategy. Please go ahead..

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 Julian Bott, 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 the Investor Relations tab that we'll be referencing during the call.

Keep in mind 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 the 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..

Thank you, Duane. Good morning, everyone. The third quarter and the weeks since the end of the quarter have been an active time for SandRidge on multiple fronts. Despite a continued volatile market backdrop, we're doing exactly what we said we would do on our last two calls.

Protect and ensure adequate liquidity, capital allocation will be rigorous and dynamic, and we will reduce our debt. Along those lines, we have four major themes to cover today. Our operating results, the Niobrara Shale acquisition, progress on debt reduction and liability management, and how we're thinking about 2016 and beyond.

Before I begin, as I think about what we've accomplished this year.

If in January of 2015, you would have told me that in the calendar year we would be able to get well costs below $2.3 million per lateral, take out $1 dollar per Boe of lease operating expenses, put extended laterals into the Chester and Woodford, plus place $1.25 billion in a very efficient second lien, retire $525 million of unsecured notes, purchase our Piñon gathering system at approximately 3 times EBITDA, then acquire a 10-year inventory in a derisked area with 450 barrel of oil per day initial rates, I would have said that together was a low probability.

But in fact, because of our focus on multiple fronts and successive 90-day plans, we've achieved all that and we're not finished for the year. Now to the quarter and operating results, where Steve will also get into further detail. We've seen our teams execute again and continue to push our innovation, capital efficiency and safety.

This includes lowering well costs and achieving our second half 2015 (03:03) goal a full quarter early, elevating our multilateral and extended lateral program to over 50% of the wells in the quarter, high grading our development plan and achieving above type curve production results.

All of this while posting the best safety record in the history of the company. Using slide three, our production was just shy of 80,000 barrels of oil equivalent per day per for the quarter. We spent CapEx of $113 million and had $118 million of adjusted EBITDA.

Strong well results, that we will detail shortly, gave us confidence to raise the bottom end of production guidance.

So for guidance, also detailed in the appendix of our slide deck, production is up to midpoint of 29.75 million barrels of oil equivalent for the year, with reductions in guided LOE and production tax and maintaining our $700 million CapEx target. Today, we announced $190 million acquisition of North Park Basin, Colorado Niobrara assets.

Before I get into the specifics of the transaction and asset, let me answer the question why we are buying this and what it does for SandRidge. This rightsized and derisked acquisition deliberately matches our expertise with a clear line of sight to over 1,300 high return and repeatable drilling locations.

Further, this allows us to diversify and improve overall capital efficiency by concurrently developing both our Oklahoma and Kansas assets and the North Park Basin assets at a pace that high grades and allocates capital to the best projects at any given time. On page four, let me give some details of the transaction itself.

With closing expected in December, SandRidge will pay $190 million cash for 136,000 acres in the Niobrara Shale of the North Park Basin in Jackson County, Colorado. As shown on the map, the North Park Basin sits between the DJ Basin and Wattenberg Field to the East, and Sand Wash Basin to the West.

The acreage is largely contiguous, located in rural North Central Colorado and ideally suited for pad drilling. Derisking much of the acreage, 16 horizontal producers have been drilled, and we expect IP rates of 400 barrels to 500 barrels of oil per day with very little gas or water.

Current production is approximately 1,000 Boe per day, mainly from the Niobrara D, which is initially our primary target. In our view, we are paying a reasonable price for PDP and mostly PUD value based on prices very close to current strip.

One metric to note is that using a PDP value of $40 million or $40,000 per flowing Boe, our acreage paid is about $1,100 per undeveloped acre, which is very reasonable in light of the quality of the existing results from 16 wells and derisk nature of the asset.

Low costs and efficient drilling are the core of SandRidge's operating strengths, and we plan to leverage that into our North Park Basin development. We expect to drill these wells for under $4 million and encouraged that similar wells in the DJ Basin are being drilled for under $3.5 million, which gives us a target to work towards.

We're looking to book around 27 million barrels of oil equivalent at year end 2015, with 2 million barrels equivalent of PDP and $25 million of undeveloped reserves from approximately 100 PUDs. Based on existing wells, we have assigned an EUR of 311,000 barrels of oil equivalent per well with 82% oil.

Look for us to rollout full reserve and type curve details as part of our year end reserve process. The 136,000 acres are just under 50% held by production or held by the existence of two Federal units, so we have very good control over the pace and timing of development.

An d 3D seismic coverage exists over 54 square miles to help guide our development program. One of the key points of the assets are the results from existing wells, as outlined on page five.

All nine wells drilled by the seller produce an average 30-day IP of just over 500 Boe per day, with 89% oil, and the last six wells, which had improved targeting an larger stimulations yielded 577 Boe per day. Referring to page six, summary geology. Our North Park Basin Niobrara assets have a lot of similarities to the DJ Basin Niobrara.

Depths here are 5,500 feet to 9,000 feet with 450 feet to 480 feet of gross pay and 6% to 9% porosity. We have excellent oil in place at over 55 million barrels of oil per section, thermal maturity and organic content are similar to the DJ and the reservoir is overpressured.

Combined, these are very favorable characteristics for a large scale resource play. On slide seven, our development plan is to spud our first well in January and drill continuously, adding a second rig in mid 2016. Current plans call for approximately 25 wells to be drilled in 2016.

Our team has identified just over 1,300 locations for Niobrara D bench and initial spacing will be eight wells per section. Beyond our initial development, we see potential upsides from lowering well costs, proving out additional bench as productive, using our multilateral and extended lateral designs and building out infrastructure.

On slide eight, let me walk through returns of our North Park asset and compare these to our competitive Mississippian economics. Both projects have already appealing economics even at strip prices. Using last week's strip for oil and flat $2.50 gas, drilling returns on a low 30% for both the Mississippian and North Park.

North Park has more oil content and a smaller infrastructure component compared to the Mississippian. So North Park, as shown in the graph on page eight, generates higher returns as oil prices recover. Consistent with our enthusiasm for entering the Niobrara, let me highlight that this is in no way a negative statement on our Mid-Continent assets.

In fact, today, we again raised production guidance and lowered expense guidance for the Mississippian. Our leading $2.3 million per lateral costs support competitive returns there at current strip pricing.

And by moderating the pace of development, we've gained capital efficiencies that will continue to improve as we high grade our Mississippian projects. Also, the innovations from our Mid-Continent developed (08:56) will transfer and advantage us in developing the Niobrara.

Thus, both projects currently attract capital and our intent is to develop both projects each at a pace that optimizes learnings and allows for high grading, such that our capital efficiencies are expected to continue to improve.

As we considered adding assets complementary to our Mississippian play, we wanted to find something around $200 million in size, in a repeatable play, matching our horizontal drilling, and innovative cost improvement skillsets, capturing multiple upsides, including additional prospective benches and adding leverage to our drilling innovation.

We found all these elements in our North Park assets and allocated capital to this transaction to deliver not just balance sheet improvement from our liability management efforts, but also to expand our resource position in a way that matches our capabilities and enhances our overall capital efficiency.

Let me move on to review our recent activity in our debt reduction and liability management efforts. I mentioned before that debt reduction is a top priority for SandRidge and our recent actions reinforce that we are taking this very seriously and acting on it. On slide nine, we show a timeline and list of steps we've taken in the last six months.

Our actions have been very consistent with our message. Julian will provide additional details, but through our deliberate steps, we have shored up our liquidity, employed creative liability management tools and reduced total debt by $400 million since June 30. In doing so, we also reduced interest expense by approximately $40 million per year.

These debt reductions, at very large discounts to par from value have been for a combination of cash and stock. And any equity issued in connection with the convertible debt is at $2.75 per share or 700% premium to the recent share price.

It's important to note that while we're reducing debt, we have been and will continue to be very protective of the equity and mindful of any dilution. Into year end, we'll continue to assess liability management opportunities. However, during this call, we can't comment on or signal any next steps in that regard.

That takes us to today on the timeline in our Niobrara acquisition. While focus on liability management and debt reduction is critical in this environment, we also have to co-manage progress on our fundamental business of being a value-creating oil producer.

As we think about our proved reserves in this price environment, let me make some comments about the impact of lower prices on existing booked proved reserve volumes.

The contraction in SEC prices, which we estimate will be about $50 in oil and $2.65 gas at year end, down from $95 and $4.35 at year end 2014, will lead to a reduction in booked proved reserve volumes. We think approximately 5% of our total year end 2014 reserves may come off as PDP and 50% (sic) [15%] (11:40) as undeveloped.

This is a result of lower tail end-of-life volumes for PDP and applying the SEC five-year rule for PUD bookings. These are estimated price-related reductions and do not take into account reserve adds we'll make as part of the North Park acquisition.

In conclusion, we've had a very busy and productive recent period, taking advantage of dynamic market conditions. Over the last two quarters, SandRidge has made material progress in reducing debt and taking fixed costs out of our business.

We are visibly capturing balance sheet, operational and acquisition opportunities to enhance our value to investors. At the same time, our operational teams continue to improve capital efficiency in our Mid-Continent business.

And with the new Niobrara acquisition, those skilled teams will leverage our capabilities into a new area to further create value and take advantage of diverse opportunities. Now, let me turn the call over to Steve Turk..

Thank you, James, and good morning to everyone dialing in today. I'm pleased to share the details of the progress that we have made towards our objectives of reducing costs and creating efficiencies within our operations. Much of this progress builds upon initiatives that were previewed in prior quarters.

In the third quarter, total company production average 79,900 barrels of oil equivalent per day, 70,600 barrels of oil equivalent per day from the Mid-Continent. Natural base decline was a major contributor to a 10% quarter-over-quarter decrease.

Despite this quarterly decline, continued confidence in our program led us to again increase the lower end of our annual guidance range by 500,000 barrels of oil equivalent. In addition, well delivery impacted production results.

With our ongoing emphasis on capital conservation, we decreased activity to exit the quarter with four rigs, down from six rigs in quarter two. As anticipated, with this lower rig count, we delivered 35 laterals to shales (13:38) during the quarter, which was approximately 50 laterals less than quarter two.

We also reduced Mid-Continent lease operating expenses by 18% since quarter one. A reduction in power use from increased use of energy-efficient methods of artificial lift such as gas lift and rod pumps was a significant contributor to realized savings.

Eliminating generator rental equipment and moving a higher percentage of wells to purchase power was also a factor. Since the first of the year, we removed rental generation from 67 sites, and we currently have no third-party generators running. The teams continue to improve operations to deliver sustainable low drilling and completion costs.

Achieving our year end goal ahead of plan, we averaged $2.3 million per Mississippian lateral during this quarter. Slide 10 depicts how we achieved this $700,000 per lateral savings from operational efficiency gains, vendor pricing negotiations and multilateral expansion.

As previously discussed, a significant portion of our cost reduction efforts are from durable improvements and those savings will be sustained even in a rising cost environment. Multilaterals and extended laterals continue to be a prominent focus.

For the first time in the company's history, new drilling in the quarter consisted of over 50% multilaterals. As shown on slide eleven, we achieved an average per lateral cost of $2.2 million or 88% of the cost of a single lateral.

Additionally, our recent Catherine number 1 and Morton number 1 (15:19) extended lateral wells were drilled for an impressive $1.8 million and $1.6 million per lateral respectively.

The third quarter multilateral program consisted of eight extended laterals and six full section development laterals, including our first 2-mile extended lateral in the Woodford. Fourth quarter multilateral development will consist of approximately half of new drilling and will include our first Chester 2-mile extended lateral.

As previously stated, multilaterals take longer to reach peak production and often demonstrate a flatter overall profile earlier in the life of a well. Because of this, we now report multilateral performance based on an average 90-day IP and separate from single laterals.

Also shown on slide 11, with the addition of third quarter data, our multilateral program averaged a 90-day IP of 280 barrels of oil equivalent per day or 100% of our Mississippian type curve. As illustrated on slide 12, accompanying this new reporting methodology, we also highlight our analysis of single laterals to provide a historical perspective.

This quarter, high grading efforts provided 19 single laterals that averaged a 30-day IP of 447 barrels of oil equivalent per day, 127% of our Mississippian type curve, and average drilling and completion costs of $2.5 million. Also on slide 12, 180-day cumulative production from both programs continues to increase.

Outstanding performance from singles and multilaterals combined with lower well costs enhance returns and reinforce our confidence in our original Mid-Continent assets. We continue to expand our Chester and Woodford initiatives, although the declining rig count limited our activity in these plays in quarter three.

Previously, our Chester efforts were focused on Western Woods County. We now are extending the play to the southeast in Woods, Alfalfa and Major counties. Similar to the Chester, we are expanding our Woodford delineation effort into Major County.

Both plays capitalized on their proximity to our Miss acreage and infrastructure and leverage the skills that we developed in the area. We are excited to apply our extended lateral technology to the Chester and Woodford and anticipate reporting results next quarter.

As James mentioned, we are complementing our Mississippian program with the addition of our North Park Basin Niobrara oil shale asset in north central Colorado. Our proven ability to develop a large-scale play as a low-cost operator will easily migrate to the development of this horizontal, multiple-bench resource play.

In fact, several employees on our technical staff and management team have direct Niobrara development experience. The teams are poised to begin development activities immediately with 13 drilling permits in hand and 1,300 identified locations to support future expansion.

With the addition of the North Park Basin, we will have the flexibility to allocate capital between two plays and develop each in a disciplined manner. Our teams continue to deliver above expectations with their highly efficient drilling program and cost reduction achievements on our existing asset base.

The addition of high quality acreage in the North Park Basin will allow us to leverage the skills gained from our original Mid-Continent development programs and to transfer the optimized, innovative practices used there.

SandRidge is excited about this new opportunity, and I am confident that we will quickly become a performance leader in the Niobrara. I'll now turn the call over to Julian..

Thanks, Steve, and good morning to everyone. I'm delighted to have joined the SandRidge team as CFO during the third quarter. And as you can undoubtedly tell, things have been exceptionally busy.

I would like to first give you some additional details on our financial results for the quarter and then spend some time reviewing some of the highlights from the liability management initiatives that we have completed this year. Our adjusted EBITDA was $118 million compared to $161 million in the second quarter.

This $43 million decrease was almost entirely attributable to the reductions in commodity price, $22 million; and production, $20 million. Adjusted G&A went down by $2.2 million to $27.7 million for the third quarter compared to the second quarter.

Due to the continued decline in product prices, we recorded a non-cash ceiling test write-down of approximately $1 billion in the third quarter. Capital expenditures were $113 million during the quarter, a decrease of $56 million from the second quarter and in line with our expectations for the full year.

CapEx decreased due to the reduced activity level but also benefited from the innovation and rigor being applied by our operating team that, as Steve described, has cut our D&C costs by more than 20% per lateral since the beginning of the year.

Although not highlighted in the financials, we continue to make progress on selling non-strategic assets and year-to-date have realized or are in the process of closing more than $50 million of divestitures. These assets consisted of non-core real estate and oil field service equipment. We will continue to opportunistically evaluate additional sales.

With regards to hedging, our mark-to-market position was a positive $119 million as of September 30. For the fourth quarter, all of our production is hedged. Please refer to the derivative contracts table in our earnings release for additional details on our 2015 and 2016 hedging program.

As noted in the shareholder update and earnings release, we've updated guidance to raise the lower end of our production guidance from 29 million Boe to 29.5 million Boe. We also lowered our guidance for LOE and production tax expenses.

Now I'd like to talk a bit about our liquidity and liability management initiatives, and expand on some of the comments James made earlier. You will notice on page 15 that we have included the capitalization table using par values in the earnings release and presentation. The table differs from the face of our balance sheet in the 10-Q.

In particular, following our recent debt exchanges, the new convertible notes are significantly discounted from par on our balance sheet based on a fair value that was determined at issuance. We have provided a supplemental capitalization table in our earnings release to clarify the capitalization of the company at par.

So first, I'll discuss liquidity. We ended the quarter with $790 million of cash. Our cash position, pro forma for exchanges, debt repurchases, and the Piñon gathering transaction that occurred subsequent to the quarter close, was approximately $700 million.

This cash position, plus our $500 million undrawn revolver brings our total pro forma liquidity as of September 30 to approximately $1.2 billion. As we think about liquidity, you should also note that we have additional first and second lien debt capacity available beyond our current revolver, as shown on page 16.

Counting this potential availability, we could have access to $1.9 billion of capital. Beyond liquidity, we have been steadily reducing debt. This is highlighted on page 17.

As James pointed out in his remarks, we have reduced debt by $400 million since June 30 and, year-to-date, in total, have addressed $975 million of debt through exchanges and buybacks.

The convertible exchanges are a unique tool designed by our team, which effectively allows for orderly deleveraging at an effective stock price of $2.75 per share, which is much higher than today's price.

We believe these transactions reduce debt while conserving liquidity and are highly accretive to all stakeholders, given that we are eliminating debt at significantly less than par. The convertible debt also includes a mandatory conversion feature which allows SandRidge to force conversion at deep discounts to par in the future.

As can be seen on page 17, through October 31, investors have voluntary converted over $125 million of our convertible debt at an effective average price of approximately 26% of par. Including these conversions, year-to-date, we have reduced unsecured debt by over $525 million at an average price of 38% of par.

An additional $450 million of convertible debt remains outstanding and is also available for conversion to provide additional deleveraging. Further, we have not just been addressing leverage through debt reduction. We have also been looking to address other contractual liabilities.

In particular, we acquired the Piñon gathering system for $48 million of cash and $78 million of incremental second lien debt. The transaction provides incremental annual EBITDA of $40 million, benefit SandRidge's credit profile, and was effected at approximately 3 times EBITDA.

In summary, we value our liquidity and have been active, creative, and opportunistic in taking steps to manage our balance sheet through this downturn, while using minimal liquidity in our liability management program. We will continue to be flexible and responsive to market conditions as we move forward.

That concludes my remarks, so let me now turn it back to James..

This is James. I just wanted to clarify one thing in speaking about our year-end reserves. I said 5% of our reserve will come off as PDP and 15% as undeveloped. I may have said 50%, but that's 5% and 15%, and that is off the year end 2014 numbers, so just over 500 million barrels, but I wanted to clarify that.

Operator, please open up the line for questions..

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

Hey, James. Good morning. This is Will for Neal..

Yes, Will..

First question, I guess, on the North Park acquisition, can you help us understand, I guess from an operational standpoint, when you all look at it, is there some low hanging fruit that you all see? I mean you addressed the well costs, I'm wondering if there's anything else there..

Well, well cost is one. I think the ability of the teams to drill medium depth horizontal wells, deploying our multilateral and long lateral technologies.

I would say also the experience the teams have in the Mid-Continent with our 1,300 wells in terms of optimizing artificial lift, whether we go from jet pump to Bean pump or start on Bean pump or use ESPs, a lot of artificial lift experience, and the last one would be infrastructure.

A lot of experience building infrastructure, be it gas gathering, water gathering, or crude lines. And the last one would be probably pad drilling. We've got extensive experience in the Mid-Continent drilling off (27:34) pads, that hasn't been done yet in this space, and so we plan to employ some pad drilling..

I want to point – this is Steve Turk, I want to point out that we've cited 1,300 location potential in this acquisition. That doesn't necessarily mean we'll be drilling on 1,300 pads.

We fully intend to start out pad drilling on this asset and at the type of well spacing we're considering, eight wells per section, which is used in the DJ, we could use maybe one-quarter of that number or somewhere around 200 pads to 300 pads to fully develop the asset..

Okay, all right, thanks. And then on the capital allocation side, you talked about activity in the first part of next year, drilling a few wells and getting some rigs going.

But as you look out, I guess, beyond that, how would you think about potentially shifting capital away from the Miss and towards the North Park?.

Right, now, Will, we anticipate running a program in the Mid-Continent in the Miss and Chester and Woodford, and then also in the North Park Basin. We did say and I'm very clear with this, the capital allocation will be dynamic and projects will compete for capital.

Right now in this environment where we have Mid-Continent well costs at $2.3 million per lateral and taking down LOE, those are very competitive with the returns in North Park Basin. If we have a change in those economics for the positive or the negative, or if we have a change in crude prices, we'll make changes dynamically.

But right now we see it as a balanced program between them both..

Okay, great. Thanks, guys..

You're welcome..

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

Good morning. Just a couple of questions wrapped around the acquisition first, but it's extended. Some of the mundane – what kind of evaluation do you need to do before you start spending there and what are your commitments to hold acreage look like for 2016? That's a starter..

Yeah. So on the acreage, it's an important point, because there are Federal units there, 47% of the acreage is either held by production or held by unit. So long terms on those Federal units, too, so Adam, there's not a rush to hold acreage there.

What was the other part of your question?.

Do you have a fair amount of evaluation to do before you identify where you're going to drill and when, and any permitting and all that sort of thing?.

No. I think one of the things that's attractive about this acquisition is our predecessor companies did a very good job gathering geotechnical data, and – so we have sophisticated log suites, we have cores, we have seismic that all allow us to move into the initial phase very quickly.

So I don't think that there's a tremendous amount that we need to do before we start drilling. And as James stated, we will start drilling in January..

(31:07).

(31:09) prepared comments, we already have 13 drilling permits in hand..

Okay. And I gather you didn't get any people along with this acquisition.

Are you fully staffed for what you need?.

We'll need some field staff in the area in the North Park Basin..

Okay. And then I guess on the broader sense. You addressed this a little bit, but the competition for capital, it looks to me that your lowest risk, highest return investments would be buying back more debt.

I don't know what your limitations are at this point for using cash to purchase some of the deeply discounted debt (32:02) and just any other thoughts around that..

Yes. The capital allocation is dynamic. And you've seen in the last six months, us use capital for several different sources and buying back bonds was certainly one. We bought back $350 million bonds for cash. We've also had another $126 million bonds convert to equity as part of our convert.

So I don't think we'll use all our cash or all of our availability to buy back bonds, nor will we use it all for CapEx, nor will we use it all for acquisitions. I think we've shown a balanced approach between all three of those. And, Adam, we do have some limitations on the amount of cash we can use..

That's right. We just increased actually in our bank covenant to $275 million of which we've already used $125 million, so we have about $150 million still available..

Okay. And then lastly, I guess, in the history of this company, you've been – you and your predecessors have been in various basins and plays.

How do we think about this foray into Colorado versus other moves you might anticipate making in the near term, near and intermediate term?.

Yeah, Adam, I can't comment what happened seven years and five years ago. This is a different team than we've had and a different strategy. I think much more focused. You've seen us hone in on the Mid-Continent, define our focus area and stick to our knittings there.

We've been very deliberate about any additional steps we would take in terms of adding on assets or acquisitions. We don't do acquisitions for acquisitions' sake. We look at things all the time, and we picked this one because we think it is the exact right fit. So this is not a foray. It's very targeted and very strategic.

And I would say, on that point, with the North Park asset and our Mid-Continent position, we're pretty full in terms of what the team has to execute and deliver on right now..

Great. Thanks, everybody..

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

Morning, James, and to the rest of your team there..

Thanks, Charles..

I recognize that there's things that you guys can't talk about prospectively. But I'm wondering if you can – when I look at your balance sheet and this acquisition looks really intriguing and definitely adds a new leg for you guys.

Can you comment on what your appetite would be for another similar-sized acquisition? Presumably, you've looked at a number of them beyond just this one..

Sure, Charles. I'll never say never. But I was concluding up the comments with Adam just a second ago. I think between our 700,000 acres in the Mid-Continent, between this position and the North Park Basin, our appraisal/new venture team has a couple other concepts and tests they're working on.

But we don't need another acquisition this size right now or anytime soon. We've got plenty to keep us and our teams busy for the near future..

Okay. If you addressed that, I must have missed it.

And then, on these new assets, can you give us a vision for what success would look like in this new North Park asset at the end of 2016; the number of wells you drilled, production you think you'd get to, number of rigs, that kind of thing?.

Charles, I think we'll come out with full guidance on our Mid-Con assets and North Park Basin in the first quarter when we roll out 2016 guidance. We do plan to start with one rig, add a second rig in mid 2016. So I can say we'll drill – we'll spud approximately 25 wells in calendar year 2016.

But in terms of any rates or exit rates, don't have that yet. We do anticipate that in terms of our D&C CapEx for the year, we'll spend about 30% of that on the North Park Basin next year..

Good. That's helpful color, James. It's really interesting and interesting to watch. So thanks a lot..

Thank you, Charles..

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

Good morning, guys..

Good morning..

On the North Park asset, do you have enough gathering and takeaway capacity there for your drilling plans in 2016? And if not, could you sort of give us a sense of how much capital is going have to go into midstream?.

Sure. On the crude side, we are trucking the crude to nearby refineries and other endpoints. We anticipate continuing that for the near term. We do have a second phase which would call for pipeline takeaway capacity, that's a little ways off, but we do have a plan there.

We'll also be talking to other midstream providers and exploring some other solutions. But, again, the crude's trucked right now. For gas, we have again kind of a two-phase implementation. The first phase is just to gather gas at a central facility to capture the NGLs. The second phase, later on, would be a pipeline out into the DJ Basin.

There are also some other alternatives to getting some gas to some of the local small towns there to sell. But I would note that gas is a very small component, about 10% of the reserves here. So 82% oil, 90% liquids, and with a small 10% gas..

Thanks.

Any sense of what the capital associated with that's going to be next year or is it just a small enough number, we shouldn't worry about it?.

It's a small enough number next year. And when we come out with full guidance, we'll roll out kind of a full multiyear pipeline or infrastructure CapEx to the extent that's needed. But again, given our pace of development, we have a lot of time to get into the real capital or the meat of the infrastructure..

Okay. And then following on a little bit on Adam's earlier question, as you think about sort of capital allocation between balancing the Miss Lime between the Niobrara.

How much of that decision now is driven by a desire to go more oily given what's happened with gas prices over last year, versus thinking that this is sort of a better use of capital than the legacy Miss Lime acreage?.

As we show on the presentation deck, at today's prices, they're very close in terms of competing for capital. Now, that could change quickly. It could change with $5 move in commodity prices. It could change with driving this well cost down even further or even getting our Niobrara well cost down further.

But right now, again, I see it's a balanced program between the two. But I fully expect the program will be very dynamic and I think in the first and third quarters with – as we don't know what's going to happen with the market, it will change.

I'm not sure exactly how it's going to change, could be more towards North Park Basin, could be towards buying back bonds, could be more towards some of these other creative – I think creative liability management tools we've done.

But I think we've taken a very balanced approach to reducing debts, employing some creative liability management tactics, and adding to the asset base..

And just one last one for me. I mean, you guys highlighted the incremental senior debt capacity of the company.

Sort of any thoughts around ultimately replacing the borrowing base with a fixed rate debt just getting off the borrowing base treadmill as you head into kind of the spring 2016 redeterminations?.

Sure. It's something we always have our eye on. We pay close attention to the capital markets and what opportunities are available for us there. No plan to do that right now, but if that market were to get robust, we would certainly consider it. Our revolver at $500 million was just reaffirmed in October.

We have no first lien borrowings now and a pretty large base of PDP. So I feel pretty confident that that $500 million is very safe. But look, we all recognize the benefits of having first lien bond, if that opportunity's available, and we'll keep that as one of our options..

Great. Thank you very much..

Your welcome..

The next question comes from the line of Amer Tiwana from CRT Capital. Your line is open..

Hi, guys. My question is around the liquidity position. I know you sort of show that you have potential $1.86 billion. I guess, with this acquisition it comes down a little bit.

How do you view your liquidity position, what sort of a runway do we have at this point in point, given current oil and gas prices? And can you talk about when you viewed this acquisition, relative to your liquidity runway, how did you think about it?.

commodity price, capital spending pace, any capital market transactions we might do, further liability management tools. So I think it's premature to put out a specific liquidity timeline because there's so many different variables that go into that.

But I think we've shown throughout this year that liquidity is very important to us and we'll continue to have an adequate liquidity runway and shore that up. We did obviously look at the impact of this $190 million of cash to our liquidity position and the cash generation capability of the business.

And we think we are in a better position with this acquisition. We'll generate higher returns. We'll have a diversified portfolio. So we think this, even though we used $190 million cash, is very additive to the enterprise..

Okay, great. And a follow-up question on your saltwater disposal system.

Just wondering if you can talk about if there are any plans at this point in time? In terms of solutions, can you spin this out potentially to maybe the bondholders in order to maybe delever the company? Is that a possibility? I know the market probably for pure spin-off may not be as robust.

So can you talk about that?.

Yeah, I think your last point, probably, how I would frame that up. The MLP market and the midstream and gathering market, when we put this business – we started to think about it almost two years ago, and then filed our S1 over a year ago, was in a much different spot than it is today.

So I think the options available to us right in front of us, public market is challenging and choppy right now. We do have the S-1 on file and we'll continue to evaluate alternatives there. If that market heats up again and becomes open and active, we'll certainly pursue that.

If there's M&A opportunities that maintain our operating flexibility, we'll avail ourselves to those. So we're keeping our options open there, but the initial thought was to take it public. But again, with those markets in the position they're in, that's not going to happen right now..

Thank you very much..

Welcome..

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

Hi, good morning. Just a clarification to start with on what the North Park acquisition does to your outlook for total CapEx in 2016.

Is there some component that's additive to what would have been spent in 2016, or is the pie the same and this is purely competing for capital with the Mississippian?.

Hey, James, for 2016, we anticipate that CapEx will be lower than 2015, not ready to guide exactly what that is, we're still going through our year end budget process, but lower than 2015 and about a third of that to the North Park Basin on a D&C cost basis.

In terms of whether this is additive or replacing capital to the Mid-Continent, we'll make that decision as the years go by. And as we dynamically allocate capital, that will be split, as we can tell right now, about 70/30 on a D&C basis..

Okay, great.

And then secondly, would you anticipate any borrowing base impact from this acquisition?.

Not, initially.

With 1,000 Boe per day and the PDP value here, I think we'll drill some more wells, get some more PDP, and look to have a borrowing base impact, what, Julian, probably in the October timeframe?.

I would think so, yeah..

Okay, okay. So, probably not until later next year.

And then finally, are there additional opportunities in the North Park to acquire additional acreage or block up additional leasehold that you might be looking at?.

Not that we're looking at now. With the 136,000 acres, we have plenty to keep us busy. But look, if some things come up that are in and contiguous in our existing acreage position, we'll take a look at them, but we've got plenty to keep us busy right now..

Sure. Okay. Thank you..

Welcome..

Your next question comes from the line of Joshua Gale from GMP Securities. Your line is open..

Hi, good morning. Thanks for taking the question. I had a few questions about some of the infrastructure, the required for the acquired asset that I think you addressed, but just a few more questions on slide eight.

What's the 30-day rate that you're using to get to the 311 MBoe? Is that just the 502 Boe a day average on the prior slides?.

Very close to that, yes. So, it's about, on a Boe basis, a little over 500 Boe per day on a 30-day IP, and that's about 450 Boepd (47:23) oil and a little bit of gas..

Okay.

And then what oil price differential are you assuming?.

We're using, I believe, $11.60 right now.

The market is moving out there just due to the fact that there's been so much capacity that's either built out or being built out in the DJ Basin, and more recent differentials were in the $8 to $10 range in the last few months, and we're guardedly optimistic that that ultimately will have a positive impact on our results..

Right. And then one more question. I see you demonstrate the greater upside to IRRs and PV-10 with improving oil prices, but keeping gas flat at $2.50 and clearly that would be disadvantageous to the Miss on a comparative basis.

I'm looking at the 2016 and 2017 strips right now and I see $53 oil and $2.85 gas, I'm just – is this acquisition part of just your view that you think there's more – you think there is more upside as compared to strip in oil than in gas, and that's how you want to sort of shape the assets of the company?.

I wouldn't read too much in that, Josh. We actually just tried to keep the slide on page eight with as little moving pieces as we could, just so it's easy to follow. But I wouldn't read that into a view that we are abandoning the gas component of the Miss..

Okay. And then just sort of separate topic. On the liquidity, second lien indenture has a $950 million credit basket.

So, is the $1 billion just the $950 plus $50 million of other liens basket?.

Yes..

And then somewhat related, do you have a modified PV-10 figure as of this quarter, excluding the trust just so we can get a sense of how close you are to potentially growing those liquidity baskets if prices were to rise?.

So, the answer to the first question is yes, there's additional baskets that'll get you to that $1 billion..

Hey, Josh, and on the PV-10, we gave out a midyear PV-10 number at the strip, but we'll hold off until year end until we roll forward all our year end bookings before we give a new PV-10 at the strip number. Last one we gave was at the midyear.

But I don't think it's prudent to give a strip number on last year's reserves until you update it for year end pricing and year end changes..

Okay, but you'll have an SEC and a modified as part of your annual disclosure?.

We'll have an SEC and a strip PV-10, yes..

Great. Thank you..

Your next question comes from the line of Steven Karpel from Credit Suisse. Your line is open..

Good morning..

Morning..

Morning..

So, from listening to you discuss the acquisition, James, it seems like you had your BD guys looking at a bunch of deals.

Can you – maybe from – was your directive to go outside of the Mid-Con and expand the focus outside of the Mid-Con?.

No, Steven. We've had a appraisal/new venture group for many years. They look at – test organic concepts. They look at extending the fields that we have. In fact they're responsible for finding the Chester and Woodford programs and they also look at new opportunities.

But no, we didn't go out saying we need to be outside of the Mid-Con, and depending on how you define the Mid-Continent, we think this is in the Mid-Continent. You can call it the Rockies, but this is analogous to what we've done in Oklahoma and Kansas..

Yeah, I think there was more an emphasis on matching our core competencies and our skillsets to anything that we would consider acquiring. And we feel very strongly that our core competencies and skillsets will be applicable to the North Park Basin, so we're very excited about applying those there..

And looking at this and looking at the large PUD (52:02) component, when you contemplated doing this, did you consider bringing in a partner immediately to do this transaction, given your balance sheet?.

We didn't. I think we thought it was prudent for us to acquire it like this, go in and do some development, drill some wells. Again, we're drilling 25 wells the first year. We have better economics and a better return for us bringing a partner in a little bit later, if we choose to do that..

Understood. And then separately, Occidental, is there – remind us where you are in terms of process with them and your desire to rework that contract and if you've made any progress..

Yes. In terms of OXY, we have an under-delivery penalty to them of about $35 million a year; we accrue that quarterly. That's about the extent of it. Any change in the contract or renegotiations, can't really comment on any of those..

All I ask is then is that something you're working on potentially?.

I can't comment on something like that. We can't give specifics of any specific transactions we're working on. We look at stuff all the time.

Is that it, Steven?.

Yes..

Okay, thank you..

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

Thank you for fitting me in here.

James, maybe just to clarify your reserve comments, did the 5% reduction in PDPs factor in year-to-date drilling at all?.

No, no, that would be – if you just took year end 2014 reserves and adjusted them for estimated year end 2015 pricing, and the same comment on the undeveloped..

Okay.

So just given the level of activity this year, how are you thinking about overall kind of PDP just kind of based off the prices you used there? Are you expecting that to be higher year-over-year?.

I really can't comment on that until we finish the year end process. We'll produce, just to help you with the math, about 30 million Boe – 30 million barrels this year – barrels of oil equivalent this year. And we started the year with over 500 million barrels, but we will have bookings, both PDP and PUDs.

We'll really have to go through the detailed year end process, which the people are doing now, before we can give you a good answer to that..

Okay, that's fair enough.

And maybe just kind of thinking about that in another light, but just giving the negative free cash flow generation here in the modified ACNTA test in the second lien, I guess kind of somewhat similar to Tarek's question but how are you thinking about using that capacity before it resets with the new reserve report at year end?.

Yeah, I can't really comment on any specific transactions or what we plan to do in terms of terming that out or accessing any of those baskets..

Okay. And then maybe just kind of lastly.

In broad strokes about 16% (55:29), but when you think about managing the PDP decline versus allocating incremental capital to North Park, how are you kind of thinking about putting that together? Is a seven-rig program in the Miss enough in your mind to kind of keep you stable or what do you think needs to go on in order to – when you're managing liquidity for next year?.

Yes, it's a fair question. And we said this in the last call. We're not managing production for growth or decline – a specific decline or to keep it flat at this stage. Given where we are with commodity prices, we're making sure we're drilling economic in the highest return projects that meet our hurdles.

So if that entails a rig program that shows a decline in production, we might have to live with that for a while. I would note that over time, the reserve base, the production base will flatten out and we've got about a 35% first year decline and 25% in 2015 (56:31). We're starting to see a little flattening in that.

So the longer you go, the shallower that decline is. But we're not chasing a production rate in terms of growth or even keeping it flat..

Okay, that's helpful. Thank you very much..

You're welcome..

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

Good morning, guys..

Morning..

Just on the acquisition, could you give us a little background as to why the seller was in the market, like what drove them selling at this time?.

Yeah, I can't really comment on that. This was owned by -funded by Yorktown Partners and I can't really comment on what their specifics were in terms of why they divested the asset..

But there was a process?.

There was a process, I believe, about a year ago, but it had concluded right about the time the crude collapsed, December 1. So after that, no there was not a process. This was kind of a negotiated transaction..

And then when you look at – you mentioned you have 12 wells with production history. What's the length of that production history and then what's your – are there any other offset operators that help you with the (57:55) geology? (57:59).

Sure, there's 16 wells and we outline them on page five, seven of those were drilled by EOG between 2007 and 2010, the remaining nine were drilled by the seller. And you could note the IP rates on all nine of those wells, it was a little over 500 Boe per day.

On the last six wells, which had larger stimulations, over 1,000 pounds per foot and more stages, the IP rate was about 577 Boe per day. In terms of offset operators, no, there really aren't in the North Park Basin, although there are a large number in the Niobrara just to the East of the DJ Basin..

Yes.

And then the drilling and completion costs, are those your estimates or that's what the company's been running at right now?.

Our drilling and completion estimates were developed internally. We valued the property using drilling costs of about $5 million starting in the first year going down to $4 million and successive drops beyond that.

And we have done some very extensive research on this capping the knowledge of the vendor community there and of the other operators that are operating similar assets in the DJ Basin. And clearly we think these estimates fall right in line with where we should be.

And we also feel that we'll ramp up the learning curve very quickly with our expertise in extended lateral drilling and in pad drilling. So we're excited to undertake this project and expect improving results very quickly as far as costs go in the first year..

And I think if you look at the DJ, they're drilling their wells from anywhere from six days to 10 days spud to rig release. We start out with a conservative assumption of 20 days just on the initial wells to get up the learning curve, and then assume we get down to about 15 days..

The $3.6 million you're showing in your economics here, that seems to be a little lower than the (01:00:26) $4 million you mentioned.

Am I missing something or is that what you're saying – think the rate will be (01:00:31) once you get the number of days down?.

Yeah, once we get our days down. Yeah, we put, on the first couple wells, we assume a little higher, $5 million, in terms of just getting up a learning curve and understanding the area. We assume those will take about 20 days, and we quickly get down to 15 days, which there you would be at that sub $4 million level..

And then just I know you've talked about this in Miss and Tarek touched on this, is there any other additional costs we should be thinking about? It sounds like midstream, there isn't much.

Any facilities or anything like that we're not talking about in this number?.

The surface facilities are all built into the $3.6 million. We will have some crude gathering as we truck the crude and build the crude gathering system, we will have some midstream and crude gathering lines. But the water disposal here is minimal, it's about a 30% water cut..

Got it. And just the last question for you. Just the liability management, so the original target of $1 billion of debt reduction, I think you'd said in the past, that it was a net number that you were thinking about.

Seeing you've used cash for acquisitions, a few other things, is that still the number that you're targeting or is there some updated number you can provide for us?.

Oh, I think again, James previously had indicated $1 billion and from the $975 million we've addressed, I think we've kind of got to that point and obviously we're not going to stop here. I think that as we look going forward, the correct capitalization is dependent on so many variables with price, development activity.

So we are excited about the assets we have, and we will continue to proactively reduce the debt levels. So that we ultimately get to a point where we're rightsized for our company. So $1 billion done but still much more to go..

I appreciate the color, guys. Thank you very much..

You're welcome..

And there are no further questions at this time. I'll turn the call back to Mr. Bennett for closing remarks..

Thank you, everyone, and thanks for the thoughtful questions and paying attention to the story. We've done a lot, I think, this year. You could be hard pressed to find another one of our peers that's made as many actions as we have on the operations, the liability management, and adding substantial resources to our existing asset base.

We look forward to continuing discussions in the next couple quarters. Thank you..

Ladies and gentlemen, this concludes today's conference call. And you may now disconnect..