Good morning. My name is Scott and I will be conference operator today. At this time, I would like to welcome everyone to the Third Quarter 2016 SandRidge Energy Earnings 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. [Operator Instructions] Thank you. Duane Grubert, Executive Vice President of Investor Relations and Strategy, you may begin your conference.

Thank you, operator and welcome, everyone. Thanks 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; and John Suter, SVP of Operations. 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, adjusted G&A 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, and good morning, everyone. Before we start, as you noticed in our earnings release, our COO, Steve Turk, will be retiring at year end. We would like to recognize Steve for his excellent and lasting contribution to SandRidge as COO these last two years, despite the distractions of our broad market correction and restructuring. Under Steve's leadership our operations teams continue to safely deliver results quarter after quarter. John Suter who joined us in 2015 as Senior Vice President of Operations is assuming the role of COO. John has deep operational experience and we're excited that we have someone with his skillset on our team. As you're aware we emerge from our restructuring in early October and thoughtfully working with our new board and developing our business plan. Going forward we will create value by focusing on fully loaded risk adjusted returns as well as adding resource value. To accomplish this we will want to maintain low leverage and preserve liquidity to generate competitive returns in cash flow from the high graded harvest of our Mid-Continent position. And three, provide portfolio diversification and long-term production and reserve upside from our merging neighbor asset and expanded focus on other plays, end and near our existing Mid-Continent position. Let me talk about each of these a little further which are outlined on Slide 3 of the presentation. First, we are and will continue to conserve capital and protect our balance sheet liquidity. Evidencing this, in the third quarter as commodity prices softened we released our second rig which was drilling in Niobrara, thus going to one rig for the last twelve months of 2016. We also decreased our work over midstream and infrastructure spend by approximately $30 million. This focused reduction spending decreased our 2016 CapEx to a midpoint…

Thank you, James. During the quarter our operating teams sustained their focus on drilling an operating cost, improving efficiencies and enhancing well in completion designs in both our Mid-Continent and Colorado operating areas. Additionally, we have been able to expand our use of extended multi-lateral technology and intend to continue to refine these designs for both, the Miz [ph], and our other development projects. Throughout the quarter, our operations teams have performed in a safe and efficient manner. I am pleased to report that we have made exceptional progress on all of these fronts. Production for the quarter was $4.6 million barrels of oil equivalent, comprised of 28% oil, 24% NGLs and 48% natural gas, a priority for our team has been increasing well reliability, our improved operation center has significantly accelerated well failure response and creates a much more efficient and proactive process for managing well performance. This facility provides real-time production monitoring for over 1,900 sites and includes over 350,000 data points representing pressures, volumes, alarms, tank levels, and other operating criteria. This has contributed to an improvement in our Mid-Continent run-time of about one million barrels equivalent compared to the same period last year, this is included in our current forecast and guidance range. Activity levels have also impacted our third quarter production, it is worth noting that in the third quarter we turned six laterals to sales versus 16 laterals in the first quarter, and 15 laterals in the second quarter. Also second quarter NGL production benefited from a temporary increase in ethane recovery. In summary, improved reliability combined with the second quarter boost in NGL production allowed us to raise 2016 production guidance from a midpoint of 19.1 million 19.2 million barrels of oil equivalent. Note, we have also included in our guidance an approximate…

Thanks, Steve. In the Mid-Continent, we ran one rig through the third quarter of 2016 drilling 13 wells or the equivalent of 24 laterals for an average cost of $1.9 million per lateral. This is $392 per completed foot generating an approximate 26% cost reduction from 2015. Lower per lateral drilling and completion costs were bolstered by our proven multi and extended lateral utilization within our drilling program. In the first nine months of 2016, SandRidge drilled and completed 17 laterals using some combination of these two methods in the Mid-Continent. This was 71% of the entire Mid-Continent drilling program during the first three quarters. As you will see on Slide 5, we have a variety of innovative well-bore configurations now at our disposal to harvest resources in unique ways. Not only does it allow us to be a good environmental steward by minimizing our surface footprint but also clearly provides capital and operating expense savings in our development plans. Our Mississippian wells utilized 100% multi and extended lateral drilling technology that projects an IRR of 36% using historical realized pricing in November 2 forward strip pricing. Our first Mississippian dual co-planar extended lateral, [indiscernible] 1-2920H produced a 30-day IP and 1,100 BOE per day, comprised of 60% oil for $1.7 million per lateral and projection IRR of 32%. This is represented by the left hand diagram on Slide 5. As you will recall, SandRidge has uniquely applied the full section development multi-lateral design to the Mississippian where three or more laterals are drilled from a single well-bore. In the third quarter, we drilled and completed our ninth Mississippian full section development well, the Richey 1-21H [ph]. This is characterized by the picture on the right hand side of that same slide. The Richey exceeded expectations with a 30-day IP…

Thanks, John. To begin I think it's important to put where we are financially in context. Having emerged from the formal restructuring process in less than 120 days, essentially on level and with ample liquidity, we are very well positioned to run our business, develop our assets and take advantage of opportunities to create resource value. This would not have been achievable without the hard work of our employees and the support of our stakeholders. Moving forward, we'll begin with our capital structure details of which are on Slide 12 and 13. Post emergent it's really very straightforward, currently we have approximately $100 million in cash and $425 million less any outstanding line of credit available to drawer under our credit facility, giving us readily available liquidity of approximately $525 million. In addition to this with liquidity, we have escrowed $50 million in cash held in an account with our RBL lenders, which can be released upon certain conditions. Regarding our RBL, it is -- it has no borrowing base redetermination or typical financial covenants, until October 2018, with the only requirement being that we maintain 1.75 times PDP asset coverage until that date. In addition to our RBL, we have a $35 million note secured by our corporate real estate, interest for this note is paid in kind for the first year at 6% at 8% the second year, and 10% thereafter until maturity. Aside from this note, we have $278 million in principal amount outstanding of our zero interest mandatorily convertible note, convertible into 14.8 million common shares of equity upon maturity or certain events including stock issuances of certain size and share price, conversion by a majority of holders, maintaining a certain share price, refinancing or a change of control; the holders may convert it any time.…

[Operator Instructions] Your first question comes from the line of David Beard from Coker Palmer Institute. Your line is open.

Good morning, gentlemen, thanks for all the detail on your presentations. Could you just maybe talk a little bit about it -- now you mentioned the production decline for next year but anyway you could bracket that or conversely maybe talk about what level of spending would keep production flat or what an internal decline rate might be? Is there any way you can flush out some of those production numbers on your -- especially, on your Mid-Con asset?

Yes, there are. If you look back at our call a year ago, almost today, we said that our PDP base decline was 35% for the first year than 25% in '15, it was just a little bit rounding. Rolling forward year and putting a little, little drilling into the mix, our PDP decline now is just over 25%, if you want to get real precise, you call it 27% but right around 25%. So that's our PDP decline going forward from where we sit today. We think with some level of drilling next year, although we haven't come out with a specific production plan yet -- I think if you penciled in a decline of right around 20%, you'd be pretty close; again, that will depend on the timing and the exact amount of drilling we do next year but something in the 20% range would make sense. And that's one of a BOE basis; slightly higher decline in oil and a slightly lower in gas as we've talked about for a while in the midst overtime, the GOR increases -- a little more gas uplift later NOI [ph].

Okay. And so that 20% decline assumes what level of spending or zero level of spending and we build from there?

No, zero spending would be about a 25% decline; so with the moderate level of spending we have something in the 20%.

All right, that's helpful. Thank you.

You're welcome.

[Operator Instructions] Your next question comes from the line of Biju [ph] from Saskaheno [ph] Financial. Your line is open.

Hi, good morning. A quick question on Slide 8, the production profile for Gregory well, it shows I think artificial lifts going in about after five months or so. Is that typical -- what do you expect the wells here flowing naturally for about five months?

Yes, I'll take this. This is John. I think we generally plan on around 90 days, this was proved to be a strong well; we did get it on jet pump [ph] and this thing has just continued to outperform where were initially thought the type curve would be.

Got it. And then the $4 million well cost, is that inclusive of surfaces [indiscernible] and artificial lift?

So for the North Park, that does include the artificial lift; so whether you're at $4 million for a single or $3.5 million for extended on a per-lateral basis; that includes this first artificial lift. And when we look at kind of the fully burdened cost for that play, we include another -- about $150,000 for field gathering and -- yes, field gathering, basically. So if you want to look at fully burdened, you could add kind of $150,000 to that, to get the fully burdened cost.

Got it. Okay, thank you.

You're welcome.

Your next question comes from the line of Joseph Sotac [ph] from Trade Link. Your line is open.

Hi, thank you. I just wondered if you could disclose or tell us about drill price on completed wells; have you accumulated any of those?

We really haven't. We've been -- we run half of completion crew in the Mid-Continent and we may build wells up for a week or two, maybe a month at the most but we don't have a large inventory reducts.

Okay, thank you. And Sunday's earthquake in Oklahoma, didn't that have any -- is it going to have any impact on your production?

No, it's not -- we've analyzed that and we -- there was even a directive put out by the OCC, our nearest wells is about 53 miles away from that. So a lot of that activity recently has been very Far East of our production. We've received, over half a dozen directives from the OCC over the last year. In fact, the first one was a year ago tomorrow. In our cumulative deferral from those water reductions is under fifty barrels of oil a day. So we've not had a meaningful impact from those reductions.

Okay, thank you. You're welcome.

[Operator Instructions] Your next question comes from the line of Mathews Zimmer from Noble Americas. Matthews Zimmer, your line is open. There are no further questions in the queue at this time. I will turn the call back over to the presenters.

Thank you everyone for joining. I hope everyone got a little more sleep than we did last night with the election results; but we appreciated on dialing in for the call. This is our first call post our restructuring so we're excited to be re-listed and back in front of investors again. You look for us to continue these calls and make some non-deal investor roadshows coming up in the near future. Thank you.

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