SandRidge Energy, Inc. (SD) Q3 2016 Earnings Report, Transcript and Summary

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 of $230 million, down from our original guidance of $285 million. In this market, we will maintain a moderate development pace and low level of cash flow outspend. We will enter 2017 with no debt and over $500 million of liquidity. I want to stress two things that I'm very excited about; first, we are improving our assets every quarter by continuing to innovate with our multi-lateral design, driving down well cost in all of our plays and uncovering new opportunities. Second, I am encouraged with the production results from our initial 11 lateral Niobrara drilling program. In the Mid-Continent we continue to drive down well cost to new record lows. Also we are evaluating opportunities in other zones within our existing acreage position, particularly in the southern part of our play where the Chester, Meramec and Osage are present and being actively developed by the industry. John Suter will provide you some additional details on each of these. In the Niobrara we have completed our initial drilling program of 11 laterals and are very pleased with the results. While we are still wrapping up flowback on a few of the wells, we have a successful set of producing wells and have driven our well costs down to $3.5 million per lateral surpassing our initial goal of $3.6 million. We drilled our first long lateral, drilled our first test well into a shallower bench of the Niobrara and tested several stimulation designs and techniques. On these two primary assets; the Mid-Continent and the Niobrara; here is how we think about location inventory at current commodity prices. In the Mid-Continent, we have approximately $300 risked 1P and 2P identified and drillable locations that are all economic at current cost and prices. As we continue to reduce our costs, or if we see improvement in commodity prices, this location count will grow. Also these locations do not include any other potential zones such as Meramec or Osage. In the Niobrara, we apply risking to our 133,000 net acres. Assuming eight wells per section, we have approximately 1,300 risk [ph] locations, all of which are economic at current cost and prices. Our successful 2016 initial drilling program has given us increased confidence in the performance here and the ability to prove up a significant amount of these locations in the next few years. In terms of some additional details on our assets and results; in the Mid-Continent in 2016, we will produce approximately 18 million barrels of oil equivalent and this is the source of the majority of our cash flow. This plain encompasses 600,000 net acres of which 70% is held by production. We've drilled over 1,600 wells in the Mississippian and remain the place cost and production leader. Turning to Slide 4, we reduced average well cost of the Mississippian to below $2 million per lateral, and drove the well for $1.7 million per lateral, the lowest yet in the play. I can't stress enough how proud I am of our teams for coming up with new and creative ways to lower costs every quarter. At the same time our well results remained consistent as evidence by our 90 day cumulative production in the graph to the right. These low costs are a major factor supporting competitive returns here and have any infrastructure already in place generates a very good risk-adjusted return, even at today's commodity prices. On Slide 5, our 2016 Mississippian program represented 100% multi and extended laterals. Using actual year-to-date realized prices and forward strip prices thereafter, we project this program will generate a 36% rate of return, also if we include non-D&C spendings such as salt water disposal connections, electrical lines, and the present value of future artificial lift changes, this burdened return is 30%. Our well costs and innovation; if you've been SandRidge you may remember us drilling our first multi-lateral well in mid-2013. Since then we have drilled 123 multi or extended laterals, continue to refine and improve the design and application, push this into now two mile multi-laterals and driven the cost downward equivalent of $1.7 million per lateral. On Slide 5 you will see the two latest multi-lateral configurations we have developed. While this doesn't get a lot of industry attention yet, I do believe this is a valuable cost saving asset development technique that will become more prevalent. Wrapping up on the Mid-Continent assets, as many of you are aware industry activity in the Meramec and Osage plays in Central Oklahoma is continuing to move north and west. After careful evaluation of this potential on our existing acreage, we drilled our first two wells in the southern portion of the play in major county Oklahoma where we have approximately 40,000 net acres. While still early, we are encouraged by our position here and the ever increasing industry activity around us. We will have more results here on our next quarterly call. Turning to our Niobrara asset in the North Park basin in Jackson County, Colorado, which is shown on Slide 6. When we acquired this asset in 2015, the opportunity was particularly attractive to us and that we knew our track record of driving down well cost to be very effective here. I'm pleased to report that in just our first 11 laterals, we've already taken well costs down past our initial goal; and like we have done in the Mid-Continent, I know our teams will improve the well cost further. In terms of production results in the Niobrara, we have five SandRidge wells now with meaningful production data, and the combined results are exceeding our 315,000 barrels of oil equivalent type curve. In fact our first well, the Gregory has over 200 producing days and it's cumulative oil production is 28% of our type curve. So in the Niobrara, with well cost of $3.5 million per lateral, EUR of 315,000 barrels of oil equivalent and over 80% oil, this is a resource play that can generate meaningful value for SandRidge. So tying all this together, what does this imply for our 2017 plans and our longer-term approach to the business and developing our assets? We're working with our Board to draw out the budget for 2017. In the current pricing environment, we expect 2017 capital expenditures will be less $200 million. At this level of spending, we anticipate production to decline in 2017 as we're not driven to chase certain production rates but rather focus on creating resource value and generating returns. Even with this moderate level of activity, we can grow asset value and I'm confident that this 2017 program will generate cash flow from the Mid-Continent, unlock additional plays within our existing Mid-Continent acreage position, and further de-risk delineate and prove up the Niobrara. For the Mid-Continent, we'll be looking at projects outside of the traditional Mississippian program which is largely held by production, and expect to enter 2017 with one rig running here. Similar to 2016, this program will be primarily multi and extended lateral projects. In Niobrara, we will look to pick up a rig in early '17. Based on the success of our first extended lateral, we expect the 2017 Niobrara program to be 100% extended laterals. Other initiatives in 2017 will include further testing, additional benches, stepping out from our initial development area, completing another 3D shoot and forming two new federal units that will hold another 33,000 net acres. Being a large and contiguous oil resource play, a moderate investment in the Niobrara can prove up a very large resource base. Turning to the cost structure side of our business; given our current one rig program, our expenses need to be aligned with that of our activity level. We are taking definitive steps in the fourth quarter that will reduce our overhead costs in Q4 and in 2017. In conclusion, our 2017 program provides a good balance of liquidity preservation, compelling fully burdened project returns and importantly, progress in advancing and unlocking the asset value in our business such as praising our existing acreage in the Mid-Continent, and potentially adding significant reserves to our Niobrara position. Oil growth is a percent of our hydrocarbon mix as the clients moderate, as the Mid-Continent gets more mature, and as our 80% oil in Niobrara becomes a larger part of our production and reserves. That concludes my prepared remarks. Let me turn the call over to Steve Turk and John Sutor to go over our operations.

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 200,000 barrel of oil equivalent reduction based on the potential for [indiscernible] in our operating area during this time of year. In the first three quarters of 2016, we reduced lease operating expenses by $115 million compared to the same period in 2015 allowing us to reduce our LOE guidance. While lower activity is a contributing factor to our lower costs, the teams created $45 million of sustainable savings. Some of the key initiatives include eliminating $14 million in compressor and generator rental equipment, an $8 million reduction from the implementation of enhanced chemical inventory management and $5 million in lower labor related expenses. Additionally, our electric submersible pumps or ESPs median lifespan has doubled since 2015 from improvements in artificial lift design. This contributed to a $5 million reduction in work over and ESP replacement expense. In summary, durable cost savings and ongoing initiatives combined with enhanced utilization of our operation center allow us to reduce 2016 LOE guidance from $9.10 per barrel of oil equivalent to $8.90 per barrel of oil equivalent. Now I will turn the call over to my friend and colleague, John Sutor. As I retire, I'd like to congratulate John on his new position as SandRidge's Chief Operating Officer. John has been instrumental in executing many of the programs I've shared with you, as well as the additional initiatives he is about to cover. I appreciate the opportunity to have served as SandRidge's Chief Operating Officer. I'm proud of what the teams have accomplished these past few years, and I'm confident that I'm leaving SandRidge's operations in the most capable hands. All yours, John.

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 of 688 barrels of oil equivalent per day, comprised of 66% oil and projects and IRR of 59% percent for $1.8 million per lateral. To expand the breadth of our Mid-Continent opportunities, we are targeting additional formations and testing some new ideas in various plays on the southern portion of our acreage holding that James mentioned before. We continue to delineate and refine our Chester development concept with our improved geo-model and further completion enhancements in this formation, we really believe the Chester provides valuable inventory going forward now that we've multiple tests and meaningful cost reductions. Extended lateral drilling applications lead to a 30% reduction of per lateral cost in this place since 2015. For example, we drilled at Chester extended lateral, the ERL 24-14 one 11H-14H [ph] which produced a 30-day IP of 560 BOE per day, comprised of 62% oil for $2.1 million for lateral. Turning to a different play, we have additional activity in major county Oklahoma. Here we are specifically evaluating Osage and Meramec formations where industry activity is on the rise. We've already drilled and completed one Osage well which is currently in the early stages of the flowback, our second well has just been drilled targeting the Meramec where we expect much faster cycle times and reduced drilling costs. We will report results of these first two wells on our next call. Let's move to the Niobrara asset in the North Park Basin. You will recall we acquired 13,000 acres in December 2015. As you see on the inset map on Slide 6, the North Park Basin is located in northern Colorado between the DJ Basin to the east and the Sand Wash basin to the west. We currently have 75,000 acres which are either held by production or within federal units. As James mentioned, we have identified over 1,300 proved and probable laterals in just the Niobrara. Technical data suggest that this area has stacked a potential, and therefore could expand the number of overall opportunities. Since beginning operations in the first quarter of 2016 we have achieved several major milestones. These milestones include; strong new well production reforms and cost improvements yielding a $3.5 million per lateral benchmark on only our tenth well in the play. Additionally, we achieved a 69% reduction in drilling cycle times, drilled and completed our first Niobrara two mile extended lateral and tested in extended Niobrara bench. Our innovative SandRidge operations team has transferred the beneficial cost improvement practices in the midst lime play in Oklahoma and brings the same rigor for new process improvement to the North Park Basin. If you refer to Slide 7, you will see that we quickly deployed a rig in the asset to continue development. We drilled 10 wells for the equivalent of 11 laterals in the first nine months of 2016. We've got off to a great start with our first well, the Gregory 19H targeting the lower Niobrara and exceeded type curve production estimates with a 30-day IP of 550 BOE per day, comprise of 89% oil. The next several slides will give you real confidence that these wells are performing at/or above type curve. On Slide 8 you'll find that the Gregory has been producing for over seven months and it's cumulatively produced approximately 75 MBO. During October, the well averaged 310 BOE per day, 84% of that being oil, which is well about type curve. Moving to Slide 9, notice that the Gregory and four additional laterals in the second quarter met or exceeded type curve performance, estimates with a combined average 30-day IP of 478 BOE per day which is 90% oil. Based on the learning from our first five wells, we plan to accelerate the installation of artificial lift to maintain performance more seamlessly. Finally, as you shift to Slide 10, you will be further interested to know that the most recent 14 wells drilled and completed with more modern completion designs are on an average exceeding production type curve expectations. We are very pleased with our initial results in this play. Referring back to Slide 7; the second set of five wells, highlighted in boxes on the right side of the map was used to test technological ideas related to drilling and completion practices, that will reduce costs and improve performance. In the second quarter, we utilized both batch drilling and zipper frac-completions with a combination of both cross-link gel and slick water frac systems in a three lateral pilot program. The other two wells, the Hebron 4-18H and the Castle 1-17H20 [ph] further define our development strategy, the Hebron, a single lateral targeted a shallow interval establishing production from a second bench in this 450 to 480 foot Niobrara section. We drilled the Hebron 4-18H for approximate 3.6 million. In addition, we were able to transfer our substantial extended lateral expertise from the Mid-Continent to the Niobrara with the Castle 1-17H20, the first two mile it's extended lateral in the play. The Castle was drilled for less than $7 million or the equivalent of $3.5 million for lateral, both wells are on early flowback and results today are very encouraging. We are using the fourth quarter as an evaluation period so we can confirm well design, spacing and simulation optimization in advance of resumed drilling in early 2017 as James mentioned. We'll share our findings in well results during the fourth quarter earnings call. Continue on the Slide 11, you will note our Niobrara singles project economic returns benefiting from high oil cuts with reduced costs. With our goal to further reduce these drilling and completion costs, we're pushing the operations team to fully understand and explore the technical limits of our well design. We've experienced even better returns by now using extended lateral well designed in this play, after successfully drilling the Castle well. As you can see by the graph on the right side of Slide 11, for extended laterals, this move to drill extended laterals help us move down the cost curve projecting and to be below $3.5 million per lateral next year. This significantly improves returns when using type curve production assumptions at the November second strip. We are optimistic about our plan to exclusively drill Niobrara extended laterals next year and you can expect to see us drive cost down in the future. In closing, our operations team delivered a very good quarter by continuing to apply the latest technology to our inventory producing assets and quality drilling locations in the Mid-Continent. We are also very pleased with our early progress and successful start-up in the Colorado North Park Basin. We expanded our multi-lateral and extended lateral programs with a successful Mississippian full section development well, and promising extended lateral applications in the gesture in Niobrara plays. Improved operational efficiencies and further integration of our operations center will reduce operating cost, these combined projects would build a foundation for future expansion and continued advancement of our field processes improving across all of this. I'd like to thank our operations team for their dedication, the hard work and safe practices in making these projects successful. I'll now turn the call over to do Julian.

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. Currently we have 20.6 million shares issued of common equity and have re-listed on the NYSE. We have 14.8 million additional shares underlying the mandatory convertible debt. So you can think of that as effectively 35.4 million shares outstanding. Assuming the notes are fully converted using November 1 closing price of the $0.23 and $0.31 per share, implies an equity value of approximately $825 million. We also have warrants which are likely to be net share settled, so it's important to note that the likely potential dilution from these warrants is just a fraction of the underlying number of warrants. In summary, we now have a clean capital structure, $100 million in unrestricted cash, $50 million in cash with our RBL Banks, and an undrawn $425 million RBL. We proactively reduced CapEx this year and it is lower than the $285 million we had previously indicated. We're now guiding to $220 million to $240 million for 2016. Capital expenditures were $52 million during the third quarter, a decrease of $4 million from the second quarter. Not only have we decreased drilling activity but costs associated with our work over drilling and facility maintenance programs have positively benefited from the utilization of existing equipment from inventory and we have deferred our North Park Basin midstream projects to 2018. In addition to reduce CapEx in 2016, we have indicated that 2017 CapEx will be less than $200 million. This is consistent with our goals of protecting our balance sheet and maintaining our liquidity while commodity prices remain relatively low. This level will result in a modest outspend and demonstrates management's commitment to preserve liquidity and low leverage. Long-term, we will remain consistent with our objective of keeping conservative leverage at a level of 2.5 times or below. Moving on to our financial performance for the third quarter, I'll walk you through a few key items. Our production was 4.6 million BOE compared to 5 million BOE for the prior quarter as previously described by Steve. Correspondingly, production revenue was $100 million compared to $96 million for the second quarter. This $4 million increase was attributable to higher commodity prices, somewhat offset by lower production. LOE was $40 million compared to $43 million for the second quarter. This decrease was attributable to lower production and substantial operational cost improvements. On a BOE basis, this represents $8.68 and $8.58 respectively. Adjusted cash G&A was $3.88 per BOE for the third quarter. In light of our anticipated reduced drilling and development activity in this current commodity price environment, we are currently initiating a broad cost cutting plan that will reduce our G&A in the fourth quarter and in 2017. Our adjusted EBITDA was $65 million compared to $62 million for the second quarter. This increase was attributable to higher commodity prices, partially offset by lower production and lower LOE, partially offset by higher G&A. We recorded non-cash write-downs of approximately $354 million in the third quarter. This impairment was the result of a combination of slightly lower SEC prices, a write-down of our electrical system, and reserve performance revisions primarily associated with our gas reserves. These third quarter reserve revisions are due to change in late life gas decline rates in localized areas of the play. Based on preliminary year-end reserve work, additional downward performance revisions, again, primarily for natural gas reserves are possible as we further analyze these changing late life decline rates. Let me now go through how accounting works post emergence. Beyond this quarter, you should be aware that consistent with the merging from the restructuring on October 4, fresh start accounting will apply during our fourth quarter and not this quarter. Fresh start accounting will effectively reset our financials as of the emergence, and will have a substantial impact on our financials. We are currently working through how it will look and again, this will be evident in our next set of financials. Our intent now is just to signal that those changes are coming next quarter. An example of the impact of fresh start is that our oil and gas assets will be recorded at fair market value as of the emergent state using strip pricing whereas we apply our impairment test against SEC pricing. Given that the strip used to determine fair value at emergence was significantly higher than the expected 2016 average SEC price to be applied at year-end we are likely to record a significant ceiling test write-down due to price at year-end. This gap mandated recording of our opening balance sheet at fair value causes a likely impairment. While we're seeing softening lately, over the past few months the oil and gas markets have rebounded significantly off the highs we saw earlier this year. As a result, the company has reinstituted its hedging program and opportunistically add its hedges for the remainder of 2016 as well as for '17 and '18 at attractive prices. Please refer to the derivative contracts table in our earnings release for details on our hedging position. As of November 3, our mark-to-market was in the money to a value of about $30 million. In summary, we are in great financial position to be opportunistic. We are focused on costs and we will continue to responsibly manage our business creating resource value and a careful eye on returns, cash flow, liquidity and leverage. With that I conclude my remarks. Operator, please open the call for questions.

[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.