SandRidge Energy Inc (SD) 2013 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q3 2013 SandRidge Energy earnings conference call. My name is Glenn, and I will be your operator for today.

(Operator instructions)

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Eddie LeBlanc, Chief Financial Officer. Please proceed, sir.

Thank you, Glenn. Welcome, everyone, and thank you for joining us on our third quarter call. This is Eddie LeBlanc and with me today are James Bennett, the President and Chief Executive Officer, and David Lawler, Executive Vice President and Chief Operating Officer.

Keep in mind that today's call contains forward-looking statements and assumptions which are subject to risk and uncertainties and actual results may differ materially from those projected in these forward-looking statements. Additionally we will make reference to adjusted net income, adjusted EBITDA and adjusted -- and other non-GAAP financial measures. As required a reconciliation of the discussion of these measures can be found in our earnings release and on our website. Please note that this call is intended to discuss SandRidge Energy and not our public royalty trust. Finally you can expect to see our third quarter 10-Q filed after the market close today.

Now let me turn the call over to James Bennett.

Thank you, Eddie. First I would like to thank all of our excellent employees for their continued hard work and focus, the results of which is another strong quarter. Earlier this year we refocused the business centering around a few key themes, capital discipline, improving returns on capital, getting our cost structure in line with our asset base while at the same time continuing to grow production and assets. Operationally this required us to do several things, first high grade our development program in the Mississippi to direct our resources and into our more proven focus of Oklahoma and Kansas; second, continue to learn and improve our well performance in order to increase production rates, EURs and returns; and, third, uncover additional opportunities within our 1.8 million mid-continent acreage position. Our teams have execute on all of these fronts. Our development plan in the focus areas is on track and exceeding expectations.

IP rates and performance remain well above our type curve as shown on page 13 of our slides where a graph outlines all of our focus area wells versus type curve. Our well cost of under $3 million are the lowest in the industry, and our lease operating expenses have improved 22% year over year. On the learning side we are improving our completion methods including new frac designs, open hole completions and improved ESP placements, just to name a few. Finally and importantly, we are finding more opportunities within our acreage position. In our earnings release we mentioned a successful appraisal well in Western Cade County, Oklahoma. And Dave will talk more about our appraisal success in finding a [ped] Marmaton sand in Kansas. I think these appraisal successes are important benchmarks as we continue to find more opportunities even outside of our focus areas.

Inside our focus areas we are seeing successful results with tests in Stack, Mississippi and in Chester zones and are implementing full development programs for these. We are also beginning to test our Woodford potential. These opportunities were identified by our teams and are additive to our NAV and broaden our resource base. Also, this speaks to the competitive advantage I believe we have in this mid-continent region through the expertise of our teams, our sub surface knowledge, large acreage position and extensive infrastructure.

Turning to the quarter and 2013. The Mississippian which is the growth driver of our Company continues to perform. Miss production grew 1% quarter-over-quarter. This is despite a rig count that was 15% lower than the second quarter, 30% lower than the first, and gas takeaway constraints that have since been alleviated from some very prolific wells. We anticipate exiting the year at just over 50,000 BOE per day net Miss production compared to the third quarter average of 47,900 BOE per day. Recall that in our plan reduction in rig count. We guided to and have been projecting a slight decrease in total production in the back half of this year. However, as the rig count levels off, our total production will begin to rise in the first quarter of 2014.

The Gulf of Mexico business continues to perform and supports our onshore development, providing consistent free cash flow. In the Permian region our focus remains on fulfilling the drilling obligation of the Permian Royalty Trust which we expect to complete in the fourth quarter of next year. As a result of the strong performance in the quarter, we are increasing 2013 production guidance for the second quarter in a row and keeping CapEx unchanged at $1.45 billion. This 300,000 BOE production increase comes almost equally from contributions in our Mississippian, Permian and southern businesses. Closing with G&A for the quarter, earlier this year we set of the goal to reduce our G&A by 25%, from approximately $200 million run rate to $150 million by Q4 of this year. I am pleased to report that we have reached and exceeded that goal a full quarter ahead of expectations with an adjusted G&A run rate of $144 million. Eddie will discuss our G&A in greater detail momentarily.

In our earnings release we provided 2014 guidance which is consistent with what we have been saying for the last couple of quarters, double-digit production growth, rated heavily towards liquids, declining LOE and G&A and a flat CapEx. For 2014 we are projecting a Miss production growth rate of 35% and a 50% growth in liquids. This growth in the Miss is offsetting other declining and flat assets. In the accompanying slides we break out the growth from 2013 to 2014 by business to give more visibility into the components. So even with declining West Texas legacy gas and declining Gulf of Mexico production, the strong growth in the Miss more than offsets these and yields a double-digit production growth weighted heavily towards liquids. Also with each year this declining gas production will be less of a component of our total production mix and is being replaced with higher value and longer life liquids production and reserves.

Turning to our acreage position, in our six county focus area we have approximately 600,000 acres, which, as of quarter end, was 46% held by production. Through year end, the combination of new lease purchases and extensions of existing acreage I anticipate will end the year with the same approximate 600,000 focus area acres. In terms of how we think about de-risking our acreage, approximately 600 wells have been drilled in our focus area, developing over 400 sections where we have a controlling interest. Considering that one well in a section may de-risk several offsetting sections, we consider a large portion of our 1,080 sections with controlling interest as having been de-risked at this point.

I want to conclude talking about two important subjects that are very much interconnected. The first is organic cash flow growth, and the second is our longer-term funding. It is my belief that the investing community may not appreciate the significant changes we have made in our business and how these translate into real cash flow growth. This year we implemented a rigorous progress designed to generate cash flow growth and returns.

For example, in 2013 we significantly decreased our Mississippian per well cost, lowered LOE, lower G&A, lowered our land [spined], greatly improve the utilization of our infrastructure, thus lowering our infrastructure spending, and, at the same time, improved our IP rates and well results. Together the combination of these changes generates significant operating leverage in our business. In terms of these efficiencies, I still think that this is the best and most concrete example for the year-to-date period 2013 versus the same period in 2012. We have drilled 69 more Mississippian wells for $27 million less capital dollars.

Now let me walk through how these improvements translate into cash generation and growth. In 2012 our pro forma adjusted EBITDA, taking into account all the NDA activity was $750 million. The mid-point of our guidance for full year 2013 yields an adjusted EBITDA between $950 million and $1 billion. Subtract $50 million for the contribution of Permian assets sold in the first quarter of this year and your 2013 pro forma adjusted EBITDA is between a $900 million and $950 million. Even at the low end of this range this is a 20% year over year EBITDA growth rate with a comparable set of assets.

Now let's look forward to 2014. The midpoint of our 2014 guidance with 12% organic production growth, 24% liquids growth, G&A savings and using a $95 and $4 price deck, yields around $1.075 of EBITDA. This is $175 million or a 19% organic EBITDA growth over 2013 guidance. This also addresses another question which is how we fund the business and shrink your free cash flow deficit. It is the same answer, organic cash flow growth. If we can grow EBITDA in the 20% range and keep our CapEx flat for several years, it does not take a complicated Excel model to figure out that we close any funding shortfall quickly, increase our debt capacity every year and can keep leverage at a reasonable 3 to 3.5 times area. Couple that with $1.7 billion of liquidity, and we have a business that is funded. So when people consider our funding or think that we require a $1 billion asset monetization to survive, it may be overlooking an important fact of our business. We are generating real 20% year over year EBITDA growth, and, through our existing asset base, have the visibility to continue this for the next several years.

With that let me turn the call over to Dave Lawler for a review of our operating performance.

Thank you, James. And good morning to everyone joining us on the call. We have a fair amount of material to share with you today. In addition to providing detail around our quarterly performance, we wanted to provide you with an update on a number of important initiatives that we are pursuing across the business. While embryonic, we believe many of these initiatives have the potential to add significant value to the Company over the long-term. To facilitate this section of the call we have prepared a set of companion slides that were published this morning, so I will refer to these periodically during my comments.

Starting with CapEx, we spent proximally $329 million in the quarter which was consistent with our planned expenditures. This funding supported a 22 rig program in the Mississippian which was 15% fewer rigs then in the second quarter and 30% fewer rigs then in the first quarter. In addition, we drilled two wells and performed three operated recompletions in the off shore. In the Permian, we maintained a three rig program to meet our commitment to the Permian Royalty Trust. We were pleased with the results of our capital program and with the execution of our operating teams. We are clearly on track to meet full-year guidance of $1.45 billion.

In the Miss, we maintained an average well cost of $2.95 million in spite of drilling additional footage for deeper objectives and installing ESPs on 75% of the wells. We were able to fund this additional cost through continued reductions in our facilities expenditures and greater efficiencies associated with pad drilling. As James mentioned, the best way to highlight our ongoing improvement is to compare year-on-year performance. The first nine months of 2012 we drilled 271 wells with infrastructure for a cost of $676 million. In the first nine months of 2013, we drilled 340 wells with infrastructure for $647 million. This is 69 additional wells for $27 million less CapEx. Our team has developed a highly efficient resource conversion system in the mid-continent.

In the offshore, we have finished completion work on Green Canyon 108, number 821 and placed the well on production August 10. The well is currently producing 625 barrels of oil per day with virtually no water. We commenced drilling Green Canyon 109, number 832 during the quarter and expect the well to be online before the end of November. We are also drilled and completed High Island 31L, number 1 and are ramping up production this month. The combined net production from all CapEx activity in the third quarter is approximately 1420 BOE per day.

Moving on to third-quarter production, we delivered 8.25 million BOE, exceeding targets in each business unit. This output allowed us to increase annual guidance by 300,000 BOE to 33.6 million BOE. This increased volume is distributed equally among the offshore Permian and mid-continent. Although solid, the quarter could have been stronger. In the Miss exceptional well performance out-based the gas take away capacity of a new producing area. As a result we deferred 12 high-impact wells. We brought four of these wells online shortly after October 22, following the start up of an accelerated gas takeaway project.

To give you an idea of how strong this area is the, 4 wells are currently producing at an average rate of 895 BOE per day with 48% oil. The remaining wells are scheduled to flow over the next several months. Without the deferred wells, we delivered 104 wells to first sales with an average 30 day IP of 307 BOE per day. This rate is 13% above type curve.

In the off shore business unit we delivered 26,400 BOE per day during the quarter. We modeled approximately 167,000 BOE of hurricane deferment. That deferment was not utilized, but it was offset primarily due to multiple pipeline curtailments and a paraffin plugging issue impacting the oil export line of Vermillion 371. Combined, these issues deferred approximately 180,000 BOE. The Vermillion export line was cleared as of November 2, and we are in the process of restoring production to original rates.

In terms of cost, we continue to improve in the Miss. Operating expense decreased to an industry-leading $7.02 per BOE, or a 22% year over year improvement. This decrease is linked to a significant reduction in generator count and the virtual elimination of water hauling. We now have the lowest generator count and the lowest truck water volume since play inception. We couldn't be more pleased with the extreme focus of our teams where they are drilling only the highest rate of return wells.

Turning to our value enhancement initiatives, we have shared in the past that we believe substantial pay exists in multiple parts of our large mid-continent lease position. As shown in slide 3, some of the more prolific formations found in the region include the Marmaton, Chester, upper middle, and lower Mississippian and Woodford Shale. Our goal is to appraise these various intervals and develop them in combination. Stated a different way, given the footprint of our water disposal and electrical networks, we are looking to find and develop multiple [pave] zones in and around these distinct competitive advantages. We anticipate these projects will significantly enhance our returns.

In the quarter we achieved a measure of success in this direction. On page 4 of the slide presentation, we highlight our first Marmaton discovery in Comanche County, Kansas. The Kansas business unit identified this target through the use of an advanced geologic model and then drilled the vertical discovery well. The well delivered a 30 day IP of 496 BOE per day. This set up a delineation well which successfully extended the field. The team is now planning a multi-well horizontal development that is within two miles of our Miss production and infrastructure. In addition we are looking to extrapolate the model to other regions of Kansas.

On the Oklahoma side of the play our teams drilled two additional horizontal Chester wells. Slide 5 shows the well locations and placement of these wellbores on our acreage. We now have 4 wells with 30 day IPs of 274 BOE per day with 70% oil. Significant horizontal development is scheduled for 2014.

Moving on to slide 6, previously we have reported encouraging Stack pay results in Oklahoma. We now have encouraging results on the Kansas side of the play with the recent same section stack pay test of the upper and lower. As shown in the cube, we drilled two wells off the same pad, one in the upper and one in the lower Mississippian. The upper delivered a 30 day IP of 319 BOE per day and 456 BOE per day from the lower. The gas to oil ratio and oil gravity are different in each wellbore. While it is still early in the evaluation process, we believe significant future development is possible in this area.

Slide 7 is an example of a multi-section upper and lower Mississippian development underway in Grant County, Oklahoma. In these four sections we are planning to add a significant number of dual and single laterals. We believe this development will generate a high rate of return, since the combination of 2 upper and 5 lower tests average more than 400 BOE per day.

Now turning to slide 8. As the industry is beginning to appreciate the Woodford Shale in north-central Oklahoma has significant development potential, recent activity is moving from South to North and leading us to believe that material volumes may exist on our acreage and possibly directly below our Mississippian development. This slide shows our lease position in and around Grant County. In this area we have selected four industry wells to illustrate how rich the Woodford can be in this emerging play. Of particular note is a high performing well drilled by Devon. This well IPd at 295 barrels of oil per day and is situated in the middle of our leasehold.

In addition Plymouth, Marsellus, and Thompson wells are located within a few miles of our acreage. Both are highly productive. In order to test the Woodford, SandRidge is drilling a total of nine wells in five different counties in 2013. To date we have completed three wells with one well still in flow back. Of the three wells, we achieved test rates of 68 barrels of oil per day and 37 barrels of oil per day. One well has produced only water. We have captured key learnings from these early wells, and we are putting together a large 3D seismic shoot that we expect to launch in 2014. We are confident that our wells will improve as we increase our knowledge of the play.

Turning to slide 9, this is a list of key initiatives that we are testing to determine if the EUR of our Miss wells can be improved through changes in stimulation technique and wellbore configuration for a lower overall cost. We are gaining more knowledge of the natural fracture systems across the play and the degree of contribution these fractures add to overall production rates. As such we are shifting more of our wells to open hole packer systems to ensure we are benefiting from the natural fracture networks. We are also testing dendritic fracture techniques to determine if this method will increase near wellbore fracture swarms.

This program is being compared to offset wells with cemented liners. In addition to the open hole packers and the dendritic stimulations, we are also landing production liner tops at 90 degrees so we can install ESPs directly in the producing interval. This option provides the lowest [resible] pressure possible early in the life of the well. This configuration also provides the opportunity to install horizontal beam pumps later in well life as water rates increase. We are testing if this combination of artificial lift systems will provide the best value and secure a higher EUR by decreasing abandonment pressure below that provided by gas lift systems.

Slide 10 is our best example of these 3 systems at work. As shown in the graph two same section wells are contrasted. Well number 2 utilized the three technical initiatives, and well 1 utilize our traditional design. You will note that well 2 is producing more than 200 BOE per day above well 1 at day 90. While we have seen varied results, our theory is that with similar cost the most efficient system at removing fluid over the life of the well will provide the highest NPV. You will find it interesting that both of these wells are very strong producers yet a vertical dry hole was drilled between them in 1980.

Slide 11 is an example of our latest engineering improvements with respect to surface facilities. In this case we built a centralized facility supported by a dual well pad. The total cost of the battery was just over $500,000 or about $250,000 per well. This translates into a savings of approximately $100,000 per horizontal well. We anticipate that up to 50% of our wells are candidates for this system in 2014.

Slide 12 shows our latest innovation, a low-cost produced water injection well. In this example we have eliminated the facilities that would normally be associated with an injection well by placing the injection well in the same pad as the producer. This saves approximately $1 million per injection well and still allows other wells to access through interconnected water tanks.

Slide 13 highlights our well performance through the end of the quarter versus type curve for our 6 project areas. This data shows we were slightly above expectation with 211 wells in the data set. We remain optimistic that our focus areas will continue to perform at or above expectation.

Lastly, we are providing a summary of our 2014 business plan. We expect to deploy $1.5 billion next year to achieve a 24% organic growth rate in liquids and a 12% organic growth rate in total production. This plan includes the operation of 25 horizontal rigs in the mid-continent delivering 430 horizontal wells. The plan also includes a 9% reduction in operating costs and a 22% reduction in G&A. We plan to share greater detail at our analyst day which is scheduled in the first quarter of 2014.

In closing I would like to thank our employees for the tremendous volume, and exceptional quality of work delivered in the quarter. Our teams generated strong economic results in a safe manner, and we are very proud of their accomplishments. These results have position SandRidge as a competitive operator in one of the highest performing resource conversion companies in the midcontinent.

I will now turn the call over to Eddie LeBlanc, our Chief Financial Officer.

Thanks, Dave. James and David have highlighted our recent operational performance including reviewing our appraisal programs, which highlighted opportunities for our future capital expenditure program. I will discuss the financial results of operations efforts and intend to provide direction for possible future results. First let's review the current results.

When I refer to pro forma information it is actual historical results after giving retroactive effect to the Permian and Tertiary asset sales and acquisitions of assets in the Gulf of Mexico in 2012. In other words, it is the illustration of pro forma results of current SandRidge properties. Adjusted EBITDA for the third quarter of 2013 of $252 million compares quite favorably to the pro forma adjusted EBITDA for the third quarter of 2012 of $182 million, a 38% increase year over year. The 8.2 million barrels of oil equivalent in production for this current quarter is a 12% year over year increase from pro forma 7.3 million barrels of oil equivalent produced in the third quarter of 2012. As James mentioned, we have reached and exceeded our goal of a low G&A run rate of $150 million for the fourth quarter. Our adjusted G&A run rate, excluding one-time items outlined in our earnings press release, was $144 million for the third quarter. We are guiding to a $145 million run rate going forward.

As you can see on slide 14, our total production on a pro forma basis has improved year over year for the nine months ended September 30, 2013, and the adjusted EBITDA has improved significantly. Adjusted EBITDA associated with production for the first nine months ended September 30, 2013 were $740 million and 24.4 million barrels of oil equivalent, 42% and 18% increases respectively over the 9 months ended September 30, 2012. While adjusted EBITDA has benefited from our cost reduction efforts, our adjusted EBITDA growth is due to a greater extent to increases in production. Our guidance for 2014 indicates that we expect this to be a continuing trend which of course is important for our moving towards self-sustaining funding of our capital expenditure program.

Slide 15 indicates the historical production capital expenditures and the gross profit provided by the mid-con, Mississippian and development and appraisal programs and highlights both our efficiencies and capital expenditures and our trend of increasing gross profit. During 2012, we developed a significant competitive advantage in this region by building our salt water disposal system. We also built an electrical distribution system that allows us to use ESPs cost-effectively to provide for the most efficient lift method for production from our wells. In 2012, when we were in the initial development stage of the Mississippian play, our average quarterly capital expenditures exceeded gross profit from field operations by approximately $256 million. After year end 2012, we began to realize the benefits of our infrastructure efforts and our declining well cost.

The average quarterly shortfall during the second stage of development was $175 million with the third quarter of 2013 experiencing a shortfall of $98 million. As we continue to build on a base of maturing all properties we see it as further narrowing even as we step up our rig rate in 2014. We closed the third quarter with no change to our 2.35 times leverage ratio. And we had a $1.7 billion liquidity which was comprised of $920 million of cash and approximately $750 million borrowing capacity under our bank credit facility after adjustment for letters of credit. We believe this level of liquidity can take us until the end of 2015. And we expect increases in EBITDA will enable us to add borrowing capacity without significantly increasing our leverage ratio, thus expanding our liquidity well into 2016 without giving effect to other liquidity options.

We recently took advantage of the rally in crude prices and added hedges for approximately 4.2 million barrels at an average price of $92.60 bringing our total hedge position to over 31 million barrels through 2015. These hedges will provide cash flow stability and add confidence to our supported EBITDA growth. Furthermore, there are no debt maturities prior to 2020. We increased our guidance for 2013 by 300,000 BOE. The volume increases were spread across three operating regions. You will see that we have initiated separate guidance for NGLs which is due to the increase of NGLs as a component of our production stream. And we are now illustrating three price realization factors.

As shown on slide 17, our current guidance indicates an expectation of $0.50 per barrel differential reduction to WTI, an NGL pricing expectation of 33% WTI and a natural gas differential reduction to Henry Hub pricing of $0.40 per MCF. We have tightened the ranges per BOE for production taxes, DD&A other, interest expense and, due to the previously mentioned expected run rate in the third quarter, we have tightened and lowered the cash and stock portions of the G&A range. Plan for a $145 million run rate for the fourth quarter of 2014. LOE and BOE the guidance has not changed despite the improvement in our Midcon/Missippian operations, due to the fourth-quarter 2013 Century Plant under-delivery accrual that is expected to be between $30 million and $36 million and will be recorded as LOE in the quarter.

This slide displays the comparison of our revised 2013 guidance to our newly issued guidance for 2014. Our most significant driver of production is presented on the top left of the slide. On a pro forma 2013 basis, 2014 guidance indicates a year over year growth in oil production of 14% and 86% increase in NGLs for a 24% year over year liquids increase. Gas essentially remains flat. Our price realization guidance for 2014 increases the discount differential for both oil and gas and slightly increases our price realizations for NGLs. I will not review the detailed Company cost per BOE guidance numbers with you, except I will point out that G&A total guidance range incorporates the $145 million run and LOE will again be charged in the fourth quarter of 2014 for a Century Plant under-delivery accrual.

Slide 18 depicts our year over year production growth in total, by product and by production region. This slide clearly illustrates the growth in total Company production is due to the ability of the Midcon/Mississippian region significant growth in production to overcome several other regional declines in production. The growing liquids contribution to production fueled expected growth in gross profit from operations and thus the growth in EBITDA that is indicated by our 2014 guidance.

Slide 19 delves further into the guidance of our Midcon/Mississippian region. Production is expected to be increase 35% fueled by a 50% growth in liquids. It also displays the constant quarter over quarter sequential growth of production which further illustrates our increase in capital efficiency in light of the decline in rig count over the same time period.

Slide 20 compares our capital expenditures included in our revised 2013 guidance to our newly issued 2014 guidance. Total Company capital expenditures are expected to increase only $50 million year over year despite a $215 million reduction in JV carry. The total trust related capital expenditures in 2014 are expected to decline by approximately $200 million as SDR drilling obligations are anticipated to be completed in the second quarter and PER drilling obligations are expected to be completed in the fourth quarter 2014. The fulfillment of these commitments combined with other corporate obligations that will be completed in 2014 will largely offset the loss of JV caring as we move into 2015. Our infrastructure spending remains fairly flat as does work over and non-op spending, and land and seismic spending increases slightly.

This concludes my remarks. Please open up the call for question and answers.

(Operator instructions).

Neal Dingmann, SunTrust.

I guess, David, a question for you today, and this is as far as on the Marmaton obviously great result there. Your thought on the potential just on how many acres that you have maybe that type of potential and how you would -- how actively you would go about developing that?

Sure, Neil. Thanks for the question. We are very excited about the Marmaton at this point as you know. It is a regional zone, very prolific. We built the geologic model to identify this particular play, and it looks like we probably will have maybe up to seven or eight horizontals. We will have to see how it goes with the first few. But we may have seven to eight horizontals as a follow-up. Teams looking in the general area and are confident that they can find something similar. So we do not have a particular acreage number that we can share at the moment, but what we do feel like is that we can export this and find other Marmaton plays in that general area.

Okay and just one follow-up if I could. What are your thoughts -- are you more encouraged, less encouraged on the middle Miss after the result there?

We are very encouraged. For the year the 30 day IPs are very strong. What we do see, Neal, is that there is a primary producing interval that we target first and then, as we gain greater knowledge in the area, then we look to add that second wellbore. And without a doubt the middle Miss is a very strong contributor across more than one county. So we have high hopes for that zone.

Thank you all. Great color today.

Duane Grubert, Susquehanna Financial.

If you could comment a little bit on those Woodford wells, clearly a little bit disappointing, and you know that there are other wells out there. So what is your kind of ingoing hypothesis on what might be going on with these specific wells versus what might happen in the future?

Great question. On our first test we drilled what we believed was the best zone to be in. So as you know in any shale play you need to be in that brittle section of the zone, and we felt like we were in that 100% in the first well. And then we went back with our log analysis that we ran in the open hole and compared that with our frac. And what we found is that in certain parts of the wellbore we had a tough time putting the stages away. And so we have tightened up that target interval, if you will, going forward, and so we are thinking that we are going to get a better result there. And then in general we think that as we get a better understanding of the fractures in the area, we can target the fractures that are intrinsic to the Woodford, and we can be in the correct portion of the zone. We are also looking to make the fracs a little bit larger, but we did upsize those compared to the Miss.

Okay and then another place you are doing some new work in the Gulf of Mexico there is a reference to doing some Wide Azimuth work. Can you talk about what kind of potential might be there? And it sounds like you will be looking for a partner rather than doing it on your own. If you could walk us through that?

Sure. Underneath the Bullwinkle platform we have identified a significant number of Miocene age sands. They are between 15,000 and 25,000 feet, so it is a little bit outside our skill set to drill those ourselves. But we did acquire in the last several months the Wide Azimuth 3D in order to better identify those targets and illuminate the structures. We have initiated conversations with industry partners who are very interested in the prospect, and this was a prospect that was identified by Shell several years ago before we acquired the property. So we are pretty excited about the oil potential underneath Bullwinkle.

And then finally you have got some custom dual laterals. Have other operators done any dual lateral work out where you are trying it, or are you kind of pioneering that?

Duane, we feel like we are the first ones. We do not have a full view of if someone else has tried this, but to our knowledge we do not know if anyone else has performed the dual laterals.

All right. Thank you very much.

Charles Meade, Johnson Rice.

This might be best for David. I wondered if -- you touched on this a bit -- I wonder if you could give a little more detail on what your process is or what your working hypothesis is on selecting the sections to go do multiple Mississippian laterals? Is it just the productivity of the first lateral in the section, or are there other things that you are looking for?

We are taking our initial attempts based on if we have rich hydrocarbon in the area. So we are not treating this as an exploratory opportunity. So we would not drill a dual lateral or a stacked pay in areas unless we were fairly certain that it was going to be productive for us. So, as an example, what we will do is in one section we might drill an upper and in the section over we might drill a lower. And, if both of those wellbores come in per expectation, then we would start to fill in the acreage between. So we are trying to step into it and make sure that we have positive economics before we continue with the development.

Got it. That definitely adds to it -- my understanding, and that makes sense. The one other question I thought I would try is, I saw, it was good detail you offered on the open hole completions that you are doing, and you also referenced that dendritic fractures that you are trying to achieve. Presumably you have always been trying to get a complex fracture network. What are you doing differently or does it really just come from having an open hole packer?

Well, as you know the open hole packer allows the natural fracture system to contribute. And, as we are seeing more and more -- we talked about on the previous call that we have a series of variables that we look for when we are selecting our development areas. And one of those criteria is the natural fractures, and so what we are seeing over time is that we can do better with the open hole packer system, so we are moving that way. In terms of the dendritic fracs, this is one of several techniques that we are trying. And the way that a dendritic frac works is you start and stop the fracture process. And the thought there is that in some way you can contribute or enhance the fractures that are there. And so it really is just going to take some time to figure out and determine if that is going to be something that takes on a broader role in the play. But it is just part of our program to continually try to improve and see if we can get a marked uplift in production.

Great. Thank you for that detail, Dave.

Stephen Shepard, Simmons.

I was wondering if you could provide a little bit of commentary regarding the quarter-on-quarter decline in the 30 day rates in the Miss and the distribution of the results. Was that decline kind of being driven by a small number of outlier wells with very low rates, or was it a function of where you were drilling in the play? Or were there any other factors worth mentioning that drove that decline?

I will start with a couple of things. We had some strong rates in the first couple of quarters -- 345, 377. We are going to see a little variability quarter-to-quarter. We are not all that worried about it. We did point out in the earnings release that we had several very high volume wells that were constrained due to some gas take away capacity. Those have since been alleviated and have come on at rates close to 900 BOE per day so if you want to put those back into the mix, I think our rate would be higher. I think all in all we are pleased because it is still well above our type curve results which are about 270 BOE per day.

Okay. And I've got one more here. I am kind of attempting to connect the dots on all the various production forecasts you have given in the slide deck in an attempt to isolate what black oil growth in the Mississippian is going to look like on a pro forma basis next year. And I'm getting to kind of a 57% year-on-year number for oil and like a 15% year-on-year growth number for NGLs after adjusting for the Permian divestiture. Do those numbers seem reasonable? Again just trying to decompose the liquids into its component pieces, and, if not, what is your expectation for what just oil will be growth in the Miss year-on-year in 2014?

Are you talking about the whole Company or just the Mississippian?

Just the Mississippian.

So the Mississippian we have 50% liquids growth, and on a daily basis we are seeing 63 for the day versus -- a daily rate of 63 versus 46 for 2013. So 46 a day in 2013, of that 22 is liquids. So 62.6 a day in 2014 of which 33 of that is liquids. So let me give you the BOE -- I'm sorry, the oil breakout on that. Just a second. Here we go. Mississippian. So 2013 black oil, let me just give you in million barrels, and you can do the conversion -- 6.9 million barrels. 2014 black oil, 9 million barrels. And liquids would be for 2013 1.3 million barrels and for 2014 3.3 million barrels. So a 30% growth in black oil.

Okay. Thank you.

Is that what were looking for?

Yes.

Jeffrey Lambujon, Tudor Pickering Holt.

Just one quick question for me on the Woodford. Is there a view yet on the extent of the play across your leasehold? Maybe your outlook on prospectivity there, or how the asset might layer in with your operational program as far as timing and ranking goes?

Sure, Jeffrey. We have mapped the Woodford to be across a vast majority of our acreage. As you know, the question is just as you go further north, what level of productivity you will see still needs to be tested. So we do not have an exact acreage count today, and we might try to share that by analyst day. But in general the Woodford is across virtually all of our Oklahoma acreage, and we are looking pretty excited about it.

Thank you.

Adam Duarte, Omega.

Sort of a follow-up to the last question. Across all of your multi zone initiatives, how much of your acreage do you think is prospective for these types of wells? And do you have an estimate of what a potential incremental resource associated with these programs would be?

Yes, Adam. I think we will have much more detail on that at analyst day in terms of kind of mapping and acreage counts for multi zone and Woodford. We think about it like this. In our focus areas with 600,000 acres and over 3,000 net potential locations. When we say potential location that is assuming one zone. So assuming and upper Miss in most of that acreage, really all of that acreage. If we take even a portion of that acreage and assume it is prospective for Chester or Marmaton, that is all additive. Or middle Miss and lower Miss, that is all additive, and then we think a large portion of it has Woodford.

So I do not think we can come out and say that we think we have two zones across the entire focus area, but we think it is absolutely more than one. And all of that is very additive to our resource base and NAV. And we will also note that whatever other zones we can find, for the most part, we are able to develop it with our existing infrastructure, which we think is key here. So going down into these deeper and other zones using the existing electrical and saltwater disposal infrastructure makes the second and third zones much more economic even -- it's very similar producing rates, much more economic than your original target interval.

Got it. And one follow-up, in the Gulf of Mexico subsalt, can you tell us a little bit more about the JV discussions you are having in terms of what types of partners you are looking for, and do you have resource estimates for your two prospects there?

Sure. On the subsalt prospect, this is a prospect that has a very high it level of interest from the industry. We have been asked about this prospect two or three times this year alone. And what we are trying to do is select a partner that has that expertise of drilling sub salt and so we have started those conversations but it is probably too early to share data beyond that. But again we are very excited. We think we have two of the best exploration prospects in the Gulf right now between the deep Miocene underneath the Bullwinkle and the sub salt at South Pass. They are two very potentially very lucrative prospects. So we are encouraged, and we are starting conversations to select a JV partner that we think has the premium skill set to efficiently develop these with us.

Do you have estimates for the prospects?

Shell had estimated that Bullwinkle was somewhere around 200 million barrels of oil, and again that is just a Shell estimate. And we do not have a number on South Pass 60 yet.

And on Bullwinkle, remind me is that a four way closure?

These are sands that truncate against a salt diapir.

Got it. Thank you.

Adam Leight, RBC Capital Markets.

Good morning. A follow-up on the Gulf of Mexico exploration prospect. How much total capital do you think you would be willing to risk on that, and what kind of timetable? I am presuming this is relatively long lead time.

Yes. This is long lead time, Adam. This is multi year kind of stuff. It is not something that we are really set of to drill ourselves, so we would, as Dave said, look for an industry partner that has got the skill set and experience and wherewithal to do this. I cannot tell you exactly how much capital we would risk. We would weigh that with what we are doing in the rest of on share in the Mississippian. I would say it would not -- certainly would not be a material part of our capital program. It is just not in our core skill set and not high on the list of allocating capital right now, just a project this risky.

Okay. Jumping to the Miss for a second, you are talking about 30 wells producers to water disposal wells. How much of that is fully built out, and what are you looking at in terms of full capacity ratio in each area?

You know, we have steadily climbed in the last several quarters that ratio, from 7 to 1 to 12 to 15, now to 30. I do not anticipate it will stay at 30. I think 30 to 1 is a pretty high ratio. We originally developed the play thinking we could get to 10 to 1. I think we are very comfortable now we can be in that 15 to 20 to 1 range. What is going to be more important going forward, though, Adam, is the dollars we spend relative to the saltwater disposal. As we go to this low-cost disposal design that Dave talked about and we mentioned in the earnings release, we won't tie quite as many producers to that. We may tie 5, 7, maybe 10 to it, whereas if the more expensive disposal wells we can tie 15 to 20.

So we'll probably get a little bit away from this disposal ratio if you even look at our earnings slides, we are actually drilling more disposal wells next year than we will drill this year. So it may look to people like we are getting less efficient with that system, but that is not the case at all. In the saltwater disposal wells this year we will drill 32. Next year we say we are going to drill 46, but more importantly look at the dollars we are spending on saltwater disposal, a flat $55 million. So the point is we are going to drill more lower-cost disposal wells, so that ratio is going to get a little misleading going forward. I encourage people to focus on the dollars.

That is helpful. And then, jumping back on the LOE, I did not quite get everything that Eddie said. The increase in the fourth quarter that is implied, is all attributable to Century Plant, or is there something else in there that I'm missing?

A big chunk of that is the Century obligation. It is in the $33 million range, so call that $1 BOE just by itself for the full year in the fourth quarter.

Okay. And then your guidance shows G&A stepping down pretty nicely in 2014. Can you just generally give a sense of how you are getting there?

Sure. We had a pretty concentrated G&A reduction program that we started earlier this year. And we made changes in compensation programs, going to performance-based pay, other advertising, sponsorship, aviation, it really changes across the board. We, and with the help of Eddie, have kind of come in and done a bottoms up review of the business to say what kind of resources do we need to run the business? And we think at this -- we have made a big improvement down from over $200 million to what we are saying is about $145 million run rate now that we are guiding to 2014.

Okay. Thank you. That is great.

James Spicer, Wells Fargo.

Hi. Good morning. I apologize if I missed this in the guidance, but just wondering how much of your 2014 capital program is allocated to the various MidCon evaluation program versus your core Mississippian drilling program?

Sure. If you look on page 20 of our deck, it is about $50 million. So of the $1 billion, $965 million -- I'll round to $1 billion of Mississippian and MidCon spending. About $50 million of that is what we are calling our appraisal program, which would be really outside the focus areas.

Okay. That is helpful. Thanks. And then in your production guidance for 2014 are you assuming any production from the MidCon efforts?

From the appraisal efforts?

Yes.

No. I would say not none but very little production from those efforts is assumed in our guidance.

Okay. Great. And then, just more broadly, you talk about the narrowing cash shortfall gap over time as EBITDA grows and CapEx remains relatively flat. Do have any sort of target or timeframe in mind as to how this is going to progress over time?

Well, I think we can say this. With $1.7 billion in liquidity, if we were to do nothing at all, we are funded well into 2016. But we are not going to do nothing at all. We are going to grow EBITDA at a 20% clip a year. And that shrinks your funding gap every year; that adds more free cash flow; that adds more leverage ability to add on a reasonable amount of leverage at a 3 to 3.5 times. So what I think some people miss is the fact that this EBITDA growth of the business and you model that out over a couple few years, and you really shrink or eliminate that funding deficit. So we think that when people focus on the funding gap, as I said in my prepared remarks, they are missing the fact that this real cash flow growth solves that problem and solves it quickly. We are not ready to come out and say that in year X we are going to be cash flow neutral, but you can model it out of the kind of growth rate and see that we get very close and close the gap in a very comfortable way.

All right. Thank you very much.

(Operator instructions)

Richard Tullis, Capital One.

Thanks. Good morning everyone. Just a couple quick questions. The $110 million in land and seismic in 2014 CapEx, where will that be dedicated?

I think a big portion of it will be in the Mississippian. There is a small amount in the Gulf of Mexico but predominantly in the Mississippian.

Okay. And how much of that is seismic? Roughly?

I would say about $10 million.

Okay. And that is related to the seismic shoot over the sub salt?

Some of it is the offshore seismic, but a large portion of it is some Mississippian shoots as well.

Okay. How many net acres in the Miss are expired in 2014?

In the entire play, 740,000 acres expire. We have, and that is in the entire 1.8 million. We have extensions on 80% of those at $130 an acre so very low-cost extensions. In the focus areas for 2014, we have 150,000 acres expiring, extensions on 45% of those at $275 an acre. So again that is part of the reason we have this $100-ish million land budget is to extend those where needed and also to add in acreage.

Year-to-date, in the focus areas we have added about 60,000 acres through pooling and acquisition of acreage close to our best locations and best wells. So we will let some acreage expire that we do not intend to drill or do not like the risk profile of it, and we will add on better acreage. So we think as I said in the prepared remarks, we will end the year -- end this year at about 600,000 acres in our focus area.

Okay. Say this time next year, what do you think your net acreage will be in the Miss? Given the spending and the expiring.

I do not know, Richard, in the entire Miss. I do think in the focus areas it will be about the same, about 600,000.

About the same. Okay. What would be the average Miss -- middle Miss Lime well cost drilling outside the core area?

It would be probably $50,000 to $75,000 more expensive. And typically it is another 300 feet or 400 feet, and it is highly variable in terms of what you might encounter. So for instance some wells we have drilled lower Miss wells for example that required as many as 14 bits as opposed to just one bit perhaps in the upper Mississippian. So in general you are looking at perhaps an extra day of drilling, and then it would be variable just in terms of the speed of the well.

And then would be additional infrastructure costs on top of that?

Our goal is that it would be the same infrastructure that we would build out for any other portion of the play. So, it would not be different than a -- an upper or a lower on the first well, but then you would see those building economics as you continue to add various zones.

Okay. What were the cost for the Chester lower and upper Mississippian wells? I may have missed that.

Well, you know they are all in that same general range, just, that kind of $2.8 million to $3.1 million. So we would anticipate that really for an overall horizontal well, we are looking at that range, that $3 million range. But if it drills quickly it can come in at $2.7 million or $2.8 million. So we try not to put an exact price tag on the different intervals. We just kind of speak to the general piece of it. If it is deeper it will cost a little bit more, and if it is shallower it might cost $50,000 to $100,000 less.

And then just lastly, is the amount given for the Century Plant payment for under-deliverability of the CO2, is that pretty much a go forward amount?

Yes. We -- close. What we have said is net in that $30 million range next year. It ramps up annually and peaks in around the 2017 timeframe give or take in the low $40 millions and then starts to decline thereafter.

Okay. Thanks a bunch. I appreciate it.

At this time, we have no further questions. I will now turn the call over to Mr. James Bennett for closing remarks.

Thank you, everyone, for joining. Just in summary, we think we are on the right path here. We have made a lot of changes in the business this year, capital discipline, focusing on returns. And we think those are showing up in the numbers. We are consistently exceeding expectations, something that we focus on here every quarter. We think we have got a line of sight visibility into 20% cash flow growth for many years, which I think gives us nice earnings growth and closes any kind of funding gap that we have in the business. And, finally, we have got great teams of people here working every day to drive the share price and create value for our owners. So thank you for joining. We will talk to you on the next earnings call.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect and have a great day.