Amplify Energy Corp (AMPY) 2012 Q4 法說會逐字稿

Good morning, my name is Amy, and I will be your conference operator today. At this time I would like to welcome everyone to the Midstates Petroleum fourth-quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. (Operator Instructions).

Today's conference call will be available for replay beginning at 11 o'clock Eastern time today through 11.59 p.m. Eastern time on March 13, 2013. The conference ID number for the replay is 15741569. The number to dial for the replay is 1-800-585-8367 or 1-855-859-2056.

Thank you. I would now like to turn the call over to Mr. Al Petrie, Investor Relations Coordinator. Please go ahead.

Thank you, Amy. Good morning, everyone, and welcome to Midstates Petroleum's fourth-quarter 2012 earnings conference call. Joining me today as speakers on our call are John Crum, President and CEO and Chairman; Steve Pugh, our Executive Vice President and Chief Operating Officer; and Tom Mitchell, our EVP and CFO.

John will begin today's call with highlights of the fourth quarter in 2012. Steve will then provide more details on fourth-quarter operational results and plans for drilling activity for the first quarter of 2013. Tom will follow with key financial highlights of the fourth quarter and provide guidance for the first quarter and 2013. John will then wrap up with some closing comments.

Before we begin, let's get the administrative details out of the way with our Safe Harbor statement.

This conference call may contain forward-looking information and statements regarding Midstates. Any statements included in this conference call or in our press release that address activities, events, or developments that Midstates expects, believes, plans, projects, estimates or anticipates will or may occur in the future are forward-looking statements. These include statements regarding reserve and production estimates; estimated timing of production restoration; oil and natural gas prices; the impact of derivative positions; production expense estimates; cash flow estimates; future financial performance; planned capital expenditures; and other matters that are discussed in Midstates' filings with the Securities and Exchange Commission.

These statements are based on current expectations and projections about future events and involve known and unknown risks, uncertainties and other factors that may cause actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Please refer to Midstates' filings with the SEC and the 2012 Form 10-K that we filed later this month for a discussion of these risks.

I will now turn the call over to John for his comments.

Thanks, Al. Good morning, everyone, and thanks for joining us today. From our earnings release yesterday as well as our two earlier releases to preannounce production volumes and the year end reserve summary, you can see we ended 2012 on a very positive note. We continued to build on that momentum into 2013. Steve and Tom will give you some details but let me begin with a few highlights.

We hit the ground running when we assumed control of the Eagle properties last October 1. Led by our Chief Operating Officer, Steve Pugh, the integration of the Eagle employees and properties in the Midstates has gone extremely well. While we still have plenty of things to complete before we are fully integrated, we have executed out our plan strategy and are continuing to implement processes and procedures to optimize operations. Given our results to date, our purchase is certainly delivering on the expectations from our acquisition case.

I am personally more excited about the potential today than I was when we closed. Since taking over the assets October 1, production is up over 50% today. We have completed 17 wells that are on production for at least 30 days. Those 17 wells have delivered an average 30-day initial production figure of over 600 BOE per day with liquids comprising 65% of the mix.

You will note our fourth-quarter reported Oklahoma oil percentages of 31% are not reflective of our actual or expected results from our drilling programs. Tom will go over the reasons for that in his comments.

Our results to date compare very favorably with the type curves we used in analyzing the acquisition last summer and any industry experience in the play. As more data on the Mississippian Lime play becomes available, it becomes more evident that our acreage concentrated in Woods and Alfalfa Counties is very well-positioned in the heart of the play. It is still quite early in the development of this play. I am confident that our industry and our Midstates own technical team will continue to find ways to improve our drilling and completion practices, lower costs and decrease cycle times and consolidate our activity. And you will see significant additional benefits in the future.

We are enthused enough that we are adding a fifth rig to the program early in the second quarter. Originally we expected to add that rig later in the year, but early results have given us the encouragement to accelerate the activity.

In yesterday's release, we also reported additional encouraging results from horizontal drilling in Louisiana. Steve will give you more details, but at North Cowards Gully our McFatter 8H-1 has now completed and tested in an initial 14-day average IP of 1,157 BOEs per day with 80% oil. We will be spudding a third North Cowards Gully horizontal well within the next week.

We continue to expand the evaluation of the potential for application of horizontal drilling in the Wilcox to our other fields. We are currently drilling our first horizontal Wilcox test at South Bearhead Creek and next week we begin completion operations on the AKS 5H-1 which has now been successfully sidetracked with the 3,250 foot lateral in the Wilcox C interval at West Gordon.

As we have earlier indicated, we will make adjustments to our 2013 capital allocations throughout the year to the best performing assets. As a result, you will see our capital guidance indicate a slight shift towards the successes we have seen in Oklahoma. We now expect about 60% of our total 2013 capital will be invested in the Mississippian Lime.

On the other hand, as indicated above, we have some very important wells underway in Louisiana.

If we continue to see the strong results from our horizontal program there over the early part of the year, we will be positioned to rebalance the allocation accordingly always focused on the highest rate of return.

Midstates experienced a 91% sequential quarter to quarter rise in production and a 49% growth in EBITDA. Obviously those levels of increase have a lot to do with adding the Eagle assets in Q4, but we were very pleased to deliver production volumes at the top end of the guidance range, driven by strong results from new drilling in both Louisiana and Oklahoma. Our overall cost structure and other key metrics also benefited from substantial volume growth.

Our cash operating cost per BOE fell 24% from third to fourth quarter on volume growth and reflecting the lower relative cost of our new Oklahoma properties. Our year end reserves report and the summary of costs incurred for 2012 also included some very positive results. Year end reserves were up 188% to 75.5 million BOE due to a healthy combination of organic drilling success and the Eagle property acquisition.

Drillbit adds replaced by 572% of 2012 production at a cost of $21.48 per BOE. The Eagle transaction grew reserves by 35 million barrels at $19.03 per BOE. All in, finding, development and acquisition costs including the impact of revisions were $21.08 per BOE.

Looking ahead to first-quarter volumes, in our earlier release we gave you guidance of 16,300 to 17,300 BOEs per day. Until a massive snowstorm hit Northern Oklahoma last week, we were comfortably ahead of the pace to go over the top of that guidance. We had averaged just short of 18,000 barrels a day for the month of February before the storm. We saw more than 30 inches of snow and lost power to most of our production base for close to a week.

With a huge effort by our field teams to bring the production back as quickly as possible, we are now 90% recovered. We are comfortable that we will still meet our guidance range even though we estimate our loss from the storm will be around 800 BOEs per day for the quarter.

Before turning the call over to Steve, I want to give you a brief update on our Clovelly Pine Prairie litigation. We were notified in December that the Louisiana Supreme Court agreed to hear our appeal and we were very pleased that they received an early hearing. On January 30th, 2013, the court heard our arguments. We believe our case was well presented and we hope to hear their ruling before summer.

I will come back at the end of the call with some additional comments about 2013, but let's move ahead with Steve and Tom giving you more details on what has occurred during the quarter and what to expect for the balance of the year. Steve Pugh will now discuss operations.

Thank you, John, and good morning. The fourth quarter was an exciting quarter for our Company as we closed and moved quickly to integrate the newly acquired assets of the Mississippian Lime, continued to see encouraging results in the horizontal program in Louisiana, further proved repeatable and profitable results in the Pine Prairie area and made the top end of our guidance range on production.

Additionally, as John mentioned, we had significant reserves growth both from our acquisition and from our Louisiana assets. Keeping to our normal earnings call format, I will discuss Q4 results and our operational plans for 2013. Let me start with the Gulf Coast region which includes our Louisiana properties.

The Company experienced solid results in the Pine Prairie area while continuing our horizontal program in the Dequincy area. In the fourth quarter of 2012 we invested approximately $86 million in the Gulf Coast region. In the Pine Prairie area we continued our active Wilcox program and our shallow Frio and Miocene drilling program, spudding six Wilcox wells and eight shallow wells, all of which were vertical. Both programs delivered results that fit our modeled IP rates.

Average costs for Wilcox wells in the quarter were in the $2.7 million range.

In the first quarter of 2013, we are proceeding with the one rig program at Pine Prairie and will drill five to six wells. We are in the process of licensing a 3D shoot over the area and we will re-process the data. We anticipate getting the re-process data back in two to three months and expect the 3D to add to our Pine Prairie inventory.

In the Dequincy area, we have continued our evaluation of horizontal drilling. In the North Cowards Gully field, the McFatter 8H-1 was drilled to a total measured depth of 16,870 feet with a 3,350 foot lateral. The well was completed in the first quarter of 2013 with 10 frac stages and had an initial 14-day rate of 1,157 BOE per day. As expected, the well produced at a higher water cut than the Musser-Davis 8H, necessitating gas lift installation which is currently underway.

The McFatter well which cost $10 million is the first follow-up well in the same Wilcox B interval as the Musser-Davis 8H-1 well. That initial horizontal well has already produced over 145,000 BOE or approximately 850 barrels of oil equivalent per day. We are encouraged by the results of the first two horizontal wells in North Cowards Gully and will continue to delineate the field. We are currently moving a rig on to the Woods 10H-1 in the eastern section of the field and plan to spud the well shortly.

While the North Cowards Gully Wells have averaged $10 million to date, we think the go forward well cost for this type of well can be in the $8 million range. We are also testing horizontal Wilcox potential in South Bearhead Creek. We are currently drilling the Musser-Davis 33/28 HC-1, targeting the lower Wilcox. The well is expected to be completed in the second quarter of 2013. If this well is successful, we anticipate drilling two to three additional horizontal Wilcox wells in South Bearhead Creek in 2013.

In West Gordon, we reentered and sidetracked the AKS 5H-1 well and are in the process of moving the rig off location. The well reached a total measured depth of 16,800 feet with a lateral length of 3,250 feet. Completion operations will begin next week. We are planning nine frac stages utilizing the plug-and-perf method.

During the first quarter of 2013, we expect to invest $55 million to $60 million in the Gulf Coast region, drilling five to six vertical wells at Pine Prairie and two to three horizontal wells in Dequincy. Our 3D seismic programs are starting to be delivered to us. In the fourth quarter, we received a 200 square mile Fleetwood data set and we are encouraged by our preliminary interpretations. We have planned to drill our first well in the area later this year.

Additionally, we received a data set for our 72 square mile shoot over the South Bearhead Creek area in the first quarter, and we expect it to help define additional shallow targets as well as the primary Wilcox formation objectives.

Now let me move to the Mid-Continent region, which includes our Oklahoma and Kansas properties. As you may recall we announced the Eagle acquisition on August 14 and immediately began our integration process. By the time the deal closed October 1, we were well on our way to opening our new regional office in Tulsa and building the team to work the assets. 21 of the previous Eagle staff have agreed to join the Midstates team and will provide the critical express base from which to build our new Mid-Continent organization. Additionally, we transferred seven Midstates Houston employees to Tulsa, including Tom Teeley, the new region Vice President and Mitch Elkins, Vice President of Drilling and Completions, who will provide strong leadership as we move to optimize the development of our Mississippian Lime assets.

We are excited about opening a Tulsa office. We fully anticipate it adding additional Mid-Continent assets and acreage to our portfolio so it was important to us to put our regional office in a city that could support our growth with petrotechnical professionals as well as support staff. We have been able to add highly qualified individuals from industry to round out our team.

We are very pleased with the results to date. Fourth-quarter production beat the high end of our guidance range, coming in at 7,207 BOE per day. The exit rate in December was 8,173 BOE per day. In the seven days prior to the storm that John mentioned, we averaged about 10,700 BOE per day. We expect to exceed those rates in the next few days as we are just now getting all wells back online.

During the fourth quarter we had four rigs active and spud 13 operated wells and placed 14 operated wells on production. Three of the rigs were focused on drilling in our most proven area while the fourth was used to test and or retain acreage in the outlying areas. We invested approximately $40 million in the Mid-Continent region during the fourth quarter.

There has been a lot of talk about well performance in the Mississippian Lime recently. Like most plays, all acreage is not created equal and we believe our acreage position is proving to be among the best. We now have 69 wells that have been on production for at least 30 days. 36 of those wells had 30-day rates in excess of 500 BOE per day and 11 of them had 30-day rates in excess of 1,000 BOE per day. The average 30-day rate for all 69 of the wells is 586 BOE per day. These results make us very comfortable since they have outperformed the metrics we use in our acquisition analysis.

Improving spud date to first sales is one of the key initiatives for the Oklahoma team during 2013. We have transitioned all of our rigs to include top drives to improve efficiencies and will continue to make improvements to the process. We are also planning to utilize pad drilling where possible to optimize facilities, infrastructures -- infrastructure and rig moves. We expect 70% of our 2013 wells to be drilled from multiwell or existing pads.

To add a few comments about infrastructure in the region, as we have said previously, the Midstates has a concentrated position in the play that helps us optimize our infrastructure. We currently have approximately 70 wells producing in the Mississippian play and five saltwater disposal wells. To further improve efficiencies, we are using a looping strategy when constructing the SWD system to alleviate downtime should an injection well go down or we have interruptions such as the lightning strike we experienced in October.

Power supply will always be a major component to our success when producing these wells with electrical submersible pumps or ESPs. Anticipating potential supply constraints from the electric co-ops, we are proceeding with the installation of two natural gas generation sets, each capable of generating 5 megawatts of power. We believe this will improve not only our cycle time of getting wells on production, but also help the reliability of our power supply.

Looking to the first quarter of 2013, we plan to continue to run three rigs in the more proven area in the center of our acreage where most of our infrastructure is already in place. We also will have one rig testing and retaining acreage in our outlying areas. We expect to drill 13 to 15 wells during the first quarter. We are also drilling three saltwater disposal wells this year in the outlying acreage to support the development of those areas.

In total, we will invest $65 million to $70 million in the Mid-Continent region during the first quarter. Early in the second quarter, the Company expects to add a fifth rig which will also be dedicated to developing the center of our acreage position.

We have agreed to participate with Chesapeake in shooting 304 square mile 3D seismic shoot that will cover all of our acreage position. We expect to receive process data by midyear. We are excited about the potential to improve our understanding of the producing mechanisms for the play.

Finally, since closing, we have added an additional 3,800 net acres adjacent to our production and expect to close on an additional 1,600 net acres shortly.

Turning to LOE, our lease operating and workover expenses for the quarter were $11.5 million, which resulted in a unit cost of $8.05 per BOE which is a bit higher than our Q4 guidance range of $6.50 to $7.50 per BOE. The higher than expected costs were due to higher SWD and chemical cost in the Gulf Coast region. We have already improved our SWD system with the well conversion and additional piping, both of which will cut our trucking costs significantly.

On the chemical side, we have installed piping and an additional vessel which has cut our chemical usage by 90% in one area. LOE in the Mid-Continent was in line with our expectations. However, we do believe we will see lower per BOE cost as we add additional volumes through the year.

I will now turn the call over to Tom for financial results and guidance.

Good morning, everyone. As in the past I will focus on the key financial items in yesterday's release and provide you with guidance for both the first quarter and the full-year 2013.

To begin, we were very pleased with our fourth-quarter production of 15,592 BOE per day, which was on the high side of guidance. As you have heard from John and Steve, the Eagle property acquisition clearly provided us with a great new focus area to utilize our drilling and completion expertise to ramp up our production and cash flow and to optimize our capital. Adjusted EBITDA for the fourth quarter totaled $48.6 million. That is up 48% from $32.7 million in the third quarter. And note these numbers include Eagle transaction costs.

The key driver was the additional production from adding the Eagle properties in the fourth quarter as well as from our drilling activities in both Oklahoma and Louisiana.

We reported a fourth-quarter GAAP net loss of $2.4 million or $0.04 per share compared with a loss of $17.8 million in the third quarter. A large contributor to the net loss in the fourth quarter was the $12.2 million in acquisition and translation costs we incurred associated with -- at the Eagle property purchase and the related financing.

Since we reported a net loss for the fourth quarter and the convertible preferred shares did not participate in losses, the additional [common shares] that we -- that would be issued upon conversion of the preferred shares would not include or not included in per share calculation. Keep in mind that when we report GAAP net income for a quarter as compared to a loss, the common shares issuable upon conversion must be included as if the preferred shares were converted and will increase the share count.

Adjusted net income which excludes the impact of unrealized gains or losses on derivatives as well as the acquisition and transaction costs totaled $5.5 million compared to $1.7 million in the third quarter. For your reference, the reconciliations of net income to adjusted EBITDA and adjusted income are provided in the supplemental information in the earnings release.

We reported fourth-quarter Companywide mix and production of 51% oil, 19% NGLs, and 30% natural gas. Our Mid-Continent mix which includes production from the Mississippi Lime and Hunton was 31% oil, 25% NGLs, and 44% natural gas. Excluding the Hunton, the mix was 38% oil, 15% natural gas liquids, and 47% natural gas. Our oil production in that region was slightly below our guidance, due in large part to the shutdown in production we experienced in Oklahoma last October when our saltwater disposal system was impacted by a lightning strike that kept a number of higher oil content wells off-line for a month during the quarter.

We already have seen a return to a higher relative oil content in the first quarter of 2013 because producing wells have remained online in Oklahoma, plus we are enjoying the positive benefit of recent wells that have a higher oil content.

For our Gulf Coast properties, the mix of production was 68% oil, which was better than expected, 14% NGLs and 18% natural gas. As John mentioned, we have maintained our first-quarter production guidance of 16,300 to 17,300 BOE per day of which we expect our Mid-Continent properties to account for about 60% of total production. For Mid-Continent, we are guiding the first-quarter mix to be about 35% to 40% oil, 20% to 25% NGLs, and 40% to 45% natural gas, reflecting the return to a more normal higher oil content. For the Gulf Coast our guidance reflects the mix to be about 60% to 65% oil, 15% to 20% NGLs, and 20% to 25% natural gas.

Midstates' average realized price per BOE of oil before realized commodity derivatives was $98.60 in the fourth-quarter 2012 compared to $104.32 in the third quarter. Our fourth-quarter realizations reflect the impact of adding our new Oklahoma properties. Going forward, we continue to expect about a $6.00 discount WTI on our Mississippian Lime production which includes transportation.

Remember that our contracts for the sale of Louisiana Gulf Coast crude oil provide that we are paid the LLS differential to WTI on about a 30-day delayed basis. As a result, we will continue to have that one-month lag in the Louisiana price realizations. Our Louisiana realizations also reflect about $2.50 per barrel in transportation costs for trucking.

The price realizations for our NGLs before realized commodity derivatives was $33.84 per barrel in the fourth quarter compared to $35.46 in the third quarter and our natural gas price before realized commodity derivatives rose slightly to $3.10 per MCF from $2.97 per MCF in the third quarter.

The earnings release include detailed information on the hedges we have in place. Since our last call in November, we have not added any new positions. Prior to the fourth quarter we did not have any hedges on NGLs or natural gas for our Louisiana production. However, with the Eagle transaction we did assume some NGL hedges and natural gas hedges in place and we benefited from those positions in the fourth quarter.

Our website maintains details of the latest hedging information. That should give you all the information you need to work your models along with our guidance summary.

Let me now review expenses. While we split our production guidance between Louisiana and Oklahoma, I will provide guidance on expense items on a total Company basis. Lease operating and workover expenses totaled $11.5 million for the fourth quarter of $12.00 or $8.05 per BOE compared to $6.6 million or $8.72 per BOE during the third quarter. Workovers totaled $1.7 million. That compares to $800,000 in the third quarter. The increase in workover activity relates primarily to our Oklahoma properties.

While we definitely saw the benefit of lower LOE on our new Oklahoma properties, as Steve mentioned, we did have some higher costs in Louisiana that pushed our total cost a bit above the range we expected of $6.50 to $7.50 per BOE. Taking into account the cost savings Steve also described, we expect our LOE to be in the range of $7.50 to $8.00 per BOE in the first quarter. For the full year we should better that with LOE in the range of $6.00 to $7.00 per BOE as more volumes come on throughout the year.

Severance and ad valorem taxes totaled $6.8 million in the 2012 fourth quarter compared to $6.5 million in the third quarter. That is about 7.6% of sales revenues before derivatives. A bit lower than the 8.5% to 9% rate we guided to for the fourth quarter, the reason for the lower rate was the combination of an ad valorem tax credit we received in Louisiana plus lower relative severance and ad valorem taxes in Oklahoma.

Going forward, the first quarter, you can expect 8% to 9% and the full-year 2013 7% to 8% of revenue which reflects that lower rate on taxes incurred. Our fourth-quarter G&A expenses before costs associated with Eagle were $11.7 million or $8.07 per BOE compared to $7.9 million or $10.56 per BOE in the third quarter. We are about $600,000 above the high end of our guidance range, primarily due to the growth in headcount during the quarter. Fourth-quarter non-cash compensation was $900,000.

We expect our quarterly G&A in 2013 to be in the range of $10 million to $12 million and total year 2013 to be in the range of $42 million to $47 million. 15% to 20% of our G&A will be non-cash compensation. Our 2013 G&A for the first nine months includes about $2.3 million of transition services costs associated with the Eagle property acquisition trans -- and services agreement.

As John mentioned, our cash operating expenses which included LOE, workovers, severance, and ad valorem taxes and cash G&A, and excludes transaction costs, will reduce 24% to $20.26 per BOE from $26.67 BOE in the third quarter. This is another example of the positive benefit we realized from the Eagle deal, along with a continued focus on cost across the Company.

Acquisition and transaction costs associated with Eagle totaled $12.2 million in the fourth quarter, which was below our initial estimate of $14 million. These costs included advisory and legal fees and fees associated with the bridge facility that was ultimately replaced with the $600 million notes offering. Those costs are all behind us as we enter 2013.

Our DD&A rate fell to $27.17 per BOE in the fourth quarter from $40.76 per BOE in the third quarter. That lower rate reflects the lower relative cost of the proved reserves we acquired in the Eagle deal as well as the positive impact of net proved reserve additions during 2012 from our successful drilling programs in Louisiana and Oklahoma. I would assume the rate for the first quarter and balance of 2013 to be $27 to $31 per BOE.

For the fourth quarter our effective tax rate was 40% and you should expect that same rate for the first quarter and full year of 2013 and we do not expect to have a cash income tax liability in the foreseeable future.

Turning next to our capital structure. On October 1, 2012, in connection with the Eagle deal, our bank group increased our borrowing base under the revolving credit facility to $250 million and extended the maturity date to October 1 of 2017. As of the end of February we had $144 million drawn under the revolver.

Currently, we are almost complete with the regularly scheduled process of re-determining the borrowing base. Indications are that the borrowing base will be increased to $285 million. Also associated with the acquisition, we issued $600 million in senior notes and 325,000 shares of Series A preferred stock with a dividend rate of 8%.

At this point, we intend to pick the semi-annual dividend on the preferred with first dividend date coming up at the end of March.

Total interest expense incurred in the fourth quarter was $17.4 million. We expensed 54% or $9.4 million and capitalized 46% or $8 million to unproved properties.

Going forward, we will again capitalize about 40% to 50% of it to unproved properties.

During the fourth quarter, we invested $134 million in capital expenditures with $40 million in Mid-Continent properties and $86 million in the Gulf Coast. As Steve mentioned, we expect to invest $120 millions to $125 million in the first quarter with about 55% in the Mid-Continent area and 45% in Gulf Coast. For the full-year 2013, we are guiding capital expenditures to $420 million to $450 million split about 60% Oklahoma and 40% Louisiana.

With that let me now turn the call back over to John.

Thanks, Tom. As we all discussed today, the Eagle acquisition has provided us with the expanded geographical footprint, added significantly to our scope and scale, and gave us the opportunity to further employ our strong operating and technical expertise. Just as importantly it now provides us with the ability to optimize our capital allocation. We have said repeatedly since we announced the acquisition, that we would direct capital to the region where we saw the best returns and opportunity for growth. The success we described today in Oklahoma leads us to allocate a bit more capital there as we await additional results from our horizontal drilling program in Louisiana.

We have also consistently said we would continue to look at acquisitions as a means to add more scale and stability to Midstates. As you heard today, the Eagle acquisition has greatly increased our critical mass and provided the needed optionality for capital deployment. We are clearly enjoying the benefits of that transaction. We will continue to look for the chance to add to our existing core areas and will carefully review opportunities that may arise in different basins that fit our skill sets.

I hope you can cents my enthusiasm for our Company and the progress we have made this past year. We have certainly had our challenges, but I am extremely proud of the team we have put together and am confident we will continue to build on recent successes.

I do want to make sure you leave our call with a few key messages.

One, our Eagle acquisition is delivering very well on the promise we saw when we were evaluating the opportunity and we are excited about the potential to expand on our position. Two, early results of our horizontal Wilcox drilling in Louisiana continues to be positive and we have some key tests underway this quarter. Three, we will continue to find ways to profitably grow our Company by expanding our inventory of investment options both organically and by acquisition. And fourth, we have the right team in place to deliver on our promises.

In closing, we will continue to be pro active in our Investor Relations efforts through meetings with our shareholders and participating in upcoming conferences. Over the next two months we will participate in the Howard Weil conference in New Orleans, and the IPAA in New York. We hope to see some of you at these venues.

And with that, I will turn it over to Al to take questions.

Okay, Amy, we are ready to take questions. And I ask our participants to limit to one question and a follow-up. Thank you.

(Operator Instructions). Neal Dingmann, SunTrust. Your line is open.

Let's go to the next one.

Ron Mills.

Couple questions. The first one would be from the Sand Ridge analyst meeting yesterday they provided a lot of good color on the Mississippian and in particular surrounding your Woods and Alfalfa County areas. Maybe, Steve, this is for you.

Can you walk through some of the differences in the Mississippian? It looks like your IP rate compares favorably to them and the EURs that they provide for those areas look above what apparently you used for your acquisition metrics. And is some of that related to the employment of ESPs on your wells from day one versus just starting? Just looking for some color there.

Ron, I might make a comment there and if Steve wants to add to it, he can. First of all, we just got all that information ourselves. So I don't know that we have got a full analysis of what Sand Ridge's day said, but I think we were pleased to see that they are also reflecting quality results in the same areas that we have been successful in. So I think it supports our premise that we are in the right area and that we will be able to continue to deliver the results we are expecting out of it.

Did you want to add anything? I -- we will get back to you when we know a little more about what [Sand Ridge] has said.

Okay. And then when you look at your capital allocation it sounds like the fourth rig -- the fifth rig that is coming in will be another development, more in the development area. Just to clarify, Tom, the 60% Mid-Continent, 40% Gulf Coast for this year's CAPEX how does that compare to the prior guidance? I'm just saying was your prior guidance 55% in Louisiana or 55% in Oklahoma?

Our prior guidance that we had out there for full year was 55 (multiple speakers) in Oklahoma.

We just moved it up slightly.

I'll get back in line. Thanks.

Leo Mariani, RBC.

Good morning. Just question on the McFatter well. You talked about it being 80% liquids. Can you give us a split between oil and NGLs in that well?

I probably should have said it is very close to 80% oil actually and that was the case with the Musser-Davis 8H as well. So that we have got liquids on top of that. They just don't make the gas that we see in some of the other areas.

And in terms of the Mississippian, can you give us insight into where your well costs are running right now and where you think those could go by the end of the year?

Yes, we are running at about $3.6 million year-to-date and we are shooting to be in the low 3s for our full year.

I guess that is helpful. And I guess in terms of your CAPEX here you talked about $125 million for the first-quarter full-year budget of $420 million to $450 million. I guess you guys are expecting to maybe slow down a little bit during the year on CAPEX?

Yes, we have a slow down toward the last part of the year. Obviously we are hoping for good results which would leave us with some additional EBITDA which would keep us running at pace towards the end of the year. But we are -- we don't plan to outspend our capital budget right now unless we get outsized EBITDA results.

Okay. Thanks a lot.

Chad Mabry with KLR Group.

Good morning. Had a quick follow-up on the Mississippian Lime. It is my understanding that your focus to date has been on the upper bench there. Wondering if you could comment on the prospectivity of the lower benches across your position? And do you also see the Woodford Shale as being present in having the potential to be a separate producing formation there?

I am going to let Curtis Newstrom answer that. He has been studying this pretty hard.

Yes we have looked at the second bench. We haven't actively planned a well to go drill a lower bench, but we have seen encouraging results around and so we think it is perspective under our acreage. We have done a fairly large study of the Woodford potential and we think there is Woodford potential both in our acreage position in Woods and Alfalfa and even down in Lincoln County. So we are trying to get our arms around that and see if there are some opportunities there.

Great. That is really helpful. And just a quick follow-up to that. Can you comment on some of the year one declines? Any B factors that you are seeing on your wells in Woods and Alfalfa?

Yes, as it relates to that. I mean we are carrying a B factor in the order of somewhere between 1.2 and 1.5. It is still fairly early, but that tends to be in line with what we are seeing in other areas.

Great. I'll get back in queue. Thanks.

Steven Shepherd, Simmons & Company.

Good morning. I was wondering on what percent of your Mississippian wells are you using ESPs. Are you using them on all of your wells or just a select group? And if it is just a select group, have you seen any meaningful performance difference on the ones that have ESPs versus the ones that don't? Can you just provide any commentary on that?

We pretty much go to ESPs early on. We have got wells that continue to flow. As soon as we quit flowing at rate we get ESPs in the ground so, Steve, 90% of our wells are on ESP.

Right.

I guess my follow-up there would be on the 3,800 acres that you all of our recently in the mix do you care to disclose a price per acre that you paid for that?

Yes, I hate to get into giving out anything but we paid around $1,500 an acre for that on average. Obviously the closer it is to real good wells, the more cost and further way the less it costs.

That's all I got. Thank you.

Neal Dingmann, SunTrust.

Hey, Neal, you made it in. Maybe not. We may have to talk to Neal offline.

Drew Venker, Morgan Stanley.

Can you guys talk about the production growth trajectory over the year with production already running ahead of schedule?

Well, we have got a pretty big target for the year obviously. We are maintaining our guidance at 20,000 to 23,000 total for the year and that's going to kind of imply pretty close to 50% growth this year. So that is what we expect. And obviously if we can get a fast start that will make us pretty comfortable, we can deliver on that.

And just help me get -- provide some more color on the service costs I think you said Mississippian wells have cost $3.6 million year-to-date and you are targeting $3 million later in the year. Can you just provide some color where that is coming from? Is that efficiencies or costs driving (multiple speakers)?

Yes, I would say it is mostly efficiencies. As I said about 70% of our wells are going to be drilled off of multiwell pads or existing pads. So we will see certainly some efficiencies there. We are not seeing I would say material changes in service costs either way, although we are bidding more of the services that we use and I do expect that we will see some costs come down just because of that.

Thanks.

Ron Mills, Johnson Rice.

To follow up on that last question, I know part of the reason the Eagle's well cost were running a little bit higher I think we talked in the past about they were using a greater level of acid in their frac jobs. As you now have had those properties for five months under your operations how much of the cost improvement do you also think will come from changing the completions in that area?

I don't know that we are expecting a significant change there. I think what we see going on in those completions is we were using a little more acid in the Eagle completions and other people were using more sand in their completions and those costs kind of offset each other.

I think where we would expect to see the gains is just purely in efficiency. Certainly as we try to run four rigs in close proximity to each other we get some benefits out of just having our activity nearby and getting some scale out of that. And then we are going to be moving. As Steve indicated, the pad drilling operations which certainly is going to help us on rig moves, et cetera. It still takes a long time to get a rig moved from well to well.

And then last one for me on the infrastructure with four rigs in the development area, that is where your infrastructure is more built out. What is the timeframe in terms of expanding your infrastructure and being able as you move toward to the west or northwest through Woods County?

Well, I guess it depends on the results. But the drill is we told you we are going to get our cash flow up as quickly as possible this year by concentrating on the areas that we are very confident about that have had lots of drilling notionally on that kind of county line area or right on the border of Woods and Alfalfa County, that has delivered on the results. The infrastructure is built out. But we will have one and sometimes two rigs running in the more outlying areas and that will require some additional build out of infrastructure.

But our overall, I guess, capital associated with infrastructure in Oklahoma is $11 million or so. So it is not a big piece of our business.

Perfect. Thanks for all of the information.

[Vance Kaskoos], Global Credit Advisors.

Good morning. Question for you. The two natural gas generation sets that you are installing, can you provide a cost of those and how many ESPs they will be able to run each?

Yes. Preliminary cost estimates are in the $3.5 million for each one. And we will run the ESPs. I don't know that we can give you a number of wells because some of that will be backup power for the co-ops.

I got you. Do you (multiple speakers).

-- different sizes in different wells obviously.

And rough ballpark?

Well, you are going to use probably 500 per well. So.

10 to 12?

Yes, maybe 20 wells total.

Perfect. Thanks. And have you ever broken out in your LOE what the cost of saltwater disposal is?

We continue to analyze that and I think when we do the math on this, is our buckles is a wonderful formation, that takes water beautifully. We don't have to actually pump it in. It actually goes in on vacuum. So when we try to do all in cost we end up with a number around $0.50 a barrel but that would include the capital associated with drilling the saltwater disposal wells and the pipelines to lay it in. Just ongoing operating costs after we have those facilities in place, it is less than $0.20.

Perfect. Thanks a lot.

(Operator Instructions). There are no further questions at this time.

Thank you, Amy, and thank you for joining us today and we look forward to seeing you at our upcoming conferences.

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