Amplify Energy Corp.
Q4 2012 Earnings Call Transcript

Published: 6 Mar 2013

[Operator:]

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

[Al Petrie:]

Thank you, Amy. Good morning everyone and welcome to Midstates Petroleum’s fourth quarter 2012 earning’s conference call. Joining me today as speakers on our call are John Crum, President and CEO, and Chairman; Stephen 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 and 2012. Steve will then provide more details on fourth quarter operation 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, estimate 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, plan 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 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.

[John Crum:]

Thanks, Al. Good morning everyone and thanks for joining us today. From our earning release yesterday as well as our two earlier releases to pre-announce 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 mid-state has gone extremely well. While we still have plenty of things to complete before we are fully integrated, we have executed on our planned 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 on October 1, production is up over 50% to date. 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 BOEs 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 owned technical teams will continue to find ways to improve our drilling and completion practices, lower cost, 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 have 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 is now completed and tested at an initial 14-day average IP of 1157 BOEs per day with 80% oil. We would be spudding a third North Cowards Gully horizontal well within the next week. We continued 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 AKS5H-1 which has now been successfully sidetracked with a 3250-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 success as 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 had 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 benefitted 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 cost 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. Drill bit adds replaced 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 BOE 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 sort 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 are very pleased that they received an early hearing. On January 30, 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.

[Steve Pugh:]

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 8 shallow wells, all of which were vertical. Both programs delivered results that fit our modeled IP rates. Average cost 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 5 to 6 wells. We are in the process of licensing a 3D shoot over the area and will reprocess the data. We anticipate getting the reprocessed 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 3350 foot lateral. The well was completed in the first quarter of 2013 with ten frac stages and had an initial 14 day rate of 1157 BOE per day. As expected oil produced at a higher water cut in the Musser-Davis 8H necessitating gas lift installation which is currently underway. The McFatter well which costs $10 million, is the first follow-up well in the same Wilcox B interval as of 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 onto 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 33/28HC-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 re-entered 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 3250 feet. Completion operations will begin next week, we are planning 9 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 plan 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 to find 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 experience 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 exciting about opening and Tulsa office. We full anticipate adding additional Mid-Continent assets and acreage to our portfolio, so it was important to us to put our regional office in the city that could support our growth with petro-technical 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 7207 BOE per day. The exit rate in December was 8173 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 on line. 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 1000 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 used 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 we will continue to make improvements to the process. We are also planning to utilize pad drilling where possible to optimize facilities, infrastructure and rig moves. We expect 70% of our 2013 wells to be drilled for multi-well or existing pads. To add a few comments about infrastructure in the region, as we have said previously, 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 salt water 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 lightening 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 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 have planned 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 salt water 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 a 304 square mile 3D seismic shoot that will cover all our acreage position. We expect to receive processed data by mid-year. We are excite about the potential to improve our understanding of the producing mechanisms for the play. Finally, since closing, we have added an additional 3800 net acres adjacent to our production and expect to close on an additional 1600 net acres shortly. Turning to LOE, our leasing operating and work over 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 cost 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 cost 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.

[Tom Mitchell:]

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 optimize our capital. Adjusted EBITDA for the fourth quarter totaled $48.6 million, that’s up 48% from $32.7 million in the third quarter. And note these numbers include Eagle transaction cost. 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 transaction cost we incurred associated with the Eagle property purchase and the related financing. Since we reported a net loss for the fourth quarter and the convertible preferred shares do not participate in losses, the additional common shares that would be issued upon conversion of the preferred shares would not include -- are not include 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 derivates as well as the acquisition and transaction cost, totaled $5.5 million compared to $1.7 million in the third quarter. For a reference, the reconciliations with net income to adjusted EBITDA and adjusted income, are provided in the supplemental information in the earnings release. We reported fourth quarter company-wide mix of 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 shut down in production we experienced in Oklahoma last October when our salt water disposal system was impacted by a lightning strike that kept a number of higher oil content wells offline 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 discount WTI on our Mississippian Lime production which includes transportation. Remember that our contracts for the sale of Louisiana Gulf Coast crude oil provides that we are paid the LOS 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 cost for trucking. The price realization 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 includes detailed information on the hedges we have in place. Since our last call in November, we have not added any new position. 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 detail 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 work over expenses totaled $11.5 million for the fourth quarter, a 12 or $8.05 per BOE compared to $6.6 million or $8.72 per BOE during the third quarter. Work overs totaled $1.7 million. That compares to $800,000 in the third quarter. The increase in work over 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 cost 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 per BOE in the first quarter. For the full year, we should better that with LOE in the range of $6 to $7 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’s about 7.6% of the sales revenue 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 a combination of an ad valorem tax credit we received in Louisiana plus lower relative severance and ad valorem taxes in Oklahoma. Going forward, in 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 and 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 cost associated with the Eagle property acquisition transition and services agreement. As John mentioned, our cash operating expenses which includes LOE, work over, severance and ad valorem taxes and cash G&A, and excludes transaction cost, were reduced 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. Our lower rate reflects a lower relative cost to 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 increased our borrowing base under the revolving credit facility to $250 million and extended the maturity dates to October 1, 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 the 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 million 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% in Louisiana. With that, let me now turn the call back over to John.

[John Crum:]

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 the 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 we will carefully review opportunities that may arise in difference basins that fit our skill sets. I hope you can sense my enthusiasm for our company and the progress we made this past year. We have certainly had our challenges but I am extremely proud of the team we put together and I 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 exciting 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 proactive 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.

[Al Petrie:]

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

[Operator:]

(Operator Instructions) Your first question comes from the line of Neil Dingmann with SunTrust. Neil, your line is open.

[Al Petrie:]

Amy, let's go the next one.

[Operator:]

Your next question comes from the line of Ron Mills.

[Ron Mills:]

Couple of 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.

[John Crum:]

Ron, I might make a comment there and if Steve wants to add to it, he can. Look, first of all, we just got all that information ourselves, so I don’t know that we have got a full analysis of 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.

[Ron Mills:]

Okay.

[John Crum:]

If you want to add anything? We will get back with you when we know a little more about what Sand Ridge has said.

[Ron Mills:]

Okay. And then when you look at your capital allocation, it sounds like 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?

[Tom Mitchell:]

Our prior guidance that we had out there for full year was 55% in Oklahoma.

[John Crum:]

We have just moved it up slightly.

[Operator:]

Your next question comes from the line of Leo Mariani with RBC Capital Markets.

[Leo Mariani:]

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

[John Crum:]

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

[Leo Mariani:]

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

[Tom Mitchell:]

Yeah. 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.

[Leo Mariani:]

Okay. I guess that's helpful. And I guess in terms of your CAPEX here, you had 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?

[John Crum:]

Yeah, we have a slowdown towards 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 don’t plan to outspend our capital budget right now unless we get outside EBITDA results.

[Operator:]

Your next question comes from the line of Chad Mabry with KLR.

[Chad Mabry:]

Just had a quick follow-up on the Mississippi Lime. It's 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?

[John Crum:]

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

[Curtis Newstrom:]

Yeah, we have looked at the second bench. We haven’t actively planned a well to go to drill a lower bench. But we have seen encouraging results around and so we think it's prospective under our acreage. We have actually 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 is some opportunities there.

[Chad Mabry:]

Great. That's really helpful. And I guess 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?

[Curtis Newstrom:]

Yeah. 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’s still fairly early but that tends to be in line with what we are seeing in other areas.

[Operator:]

Your next question comes from the line of Steven Shepherd with Simmons & Company.

[Steven Shepherd:]

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's 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?

[John Crum:]

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

[Steve Pugh:]

Right.

[Steven Shepherd:]

And then 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?

[John Crum:]

Yeah, I hate to get into giving out anything, but we paid around 1500 an acre for that, on average. Obviously, the closer it is to real good wells the more cost and further away the less the cost.

[Operator:]

Your next question comes from the line of Neil Dingmann with SunTrust.

[John Crum:]

We may have to talk to Neil offline.

[Operator:]

Your next question comes from the line of Drew Venker with Morgan Stanley.

[Drew Venker:]

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

[John Crum:]

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’s kind of what we expect. And obviously if we can get a fast start that will make us pretty comfortable we can deliver on that.

[Drew Venker:]

And just help me get some more color on the service cost side. 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 that?

[Tom Mitchell:]

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

[Operator:]

Your next question comes from the line of Ron Mills with Johnson Rice.

[Ron Mills:]

John, I guess I can be Neil today. To follow up on that last question, I know part of the reason the Eagle's well costs 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 just come from changing the completions in that area?

[John Crum:]

I don’t know that we are expecting the significant change there. You now 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 kind of 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, to pad drilling operations which certainly is going to help us on rig moves etcetera. It still takes a long time to get a rig moved from well to well.

[Ron Mills:]

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

[John Crum:]

Well, I guess it depends on results. But you know the drill as we told you we are going to get our cash flow as quickly as possible this year by concentrating on the areas that we are confident about, that’s had lots of drilling notionally in 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's not a big piece of our business.

[Operator:]

Your next question comes from the line of (inaudible) with Global Credit Advisors.

[Unidentified Analyst:]

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

[Steve Pugh:]

Yeah. 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. And then from (inaudible) in different well, obviously.

[Unidentified Analyst:]

A rough ballpark?

[John Crum:]

Well, you can use probably 500 per well or so.

[Steve Pugh:]

10 to 12.

[John Crum:]

Yeah. Maybe 20 wells total.

[Unidentified Analyst:]

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

[John Crum:]

We continue to analyze that and I think when we do the math on this, is (inaudible) 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 kind of try to do that kind of all in costs, we end up with a number around $0.50 a barrel. But that would include the capital associated with drilling the salt water disposal wells and the pipelines laid in. Just ongoing operating cost after we have those facilities in place, it's less than $0.20.

[Operator:]

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

[Al Petrie:]

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

[Operator:]

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