Amplify Energy Corp (AMPY) 2012 Q2 法說會逐字稿

Good morning. My name is Felicia and I will be your conference operator today. At this time, I would like to welcome everyone to the Midstates Petroleum second-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). This call will also be available for replay beginning at 12 o'clock P.M. Eastern Standard Time today through 1159 P.M. Eastern Standard Time on August 20, 2012. Thank you.

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

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

We posted a slide deck on our website that contains details on items we will be discussing this morning. John will begin today's call with highlights of the acquisition we announced this morning and then provide an overview of the second quarter along with comments on our drilling and capital programs for the balance of 2012 and a preview of 2013. Steve will then provide more details on second-quarter operational results and plans for drilling activity for the third quarter. Tom will follow with key financial highlights for the second quarter and provide guidance for the third quarter. John will then wrap up with some closing comments and open up the call for questions.

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, believe, 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 SEC. 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 results or performance expressed or implied by these forward-looking statements. Please refer to Midstates' filings with the SEC, including our issued prospectus and the Form 10-Q as of June 30, 2012 to be filed shortly for a discussion of these risks.

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

Thank you Al. Good morning to all of you and thanks for joining us. Let me begin with a discussion of an exciting acquisition we announced this morning and why we feel so strongly that this is a strategic and transformative event for us. The slides we posted on the Web this morning cover the transaction and the properties in some detail, but I'd like to highlight some of the key points.

The producing fields and acreage are located in northwest Oklahoma and southern Kansas in the hot Mississippian Lime play as well as additional producing acreage in Oklahoma in the Hunton play. The properties in the Mississippian Lime are particularly appealing because they are in a market recognized emerging horizontal oil play with good predictability and solid economics. This acquisition allows us to quickly increase our scale and critical mass and balance our overall drilling risk profile.

We have assembled a very strong team designed to build a long-term oil and gas company. We believe our seasoned team has the experience and technical knowledge to operate in a wide variety of basins, and our new business group is continually looking for new opportunities to utilize that experience.

The assets we are acquiring from Eagle Energy, a private E&P company based in Tulsa that was funded by Riverstone, they have -- Eagle has been one of the leading operators in this fast-developing play. Of the 103,000 acres being acquired, 84,000 acres are located in the Mississippian Lime play in or near the heart of industry activity in Woods and Alfalfa County where the larger industry players like SandRidge and Chesapeake have been quite active. Eagle has drilled over 60 horizontal wells in the play since June of 2010.

We believe this transaction -- this acquisition is very attractive for a number of reasons. First, it increases our reserves by over 140% by adding 37 million barrels equivalent of liquid-weighted proved reserves that are 35% oil, 23% NGLs. And 35% of those reserves are already proved developed producing. Post transaction Midstates will have over 63 million barrels of proven reserves with 45% of that oil and 20% NGLs.

The transaction increases our reserve life to 11.4 years. The assets being acquired have a reserve-to-production ratio of 14.5 years.

We double our producing well count by adding 114 gross producing wells with net production of about 7000 BOE per day. 85% of the wells are operated. And we believe that the infrastructure is in place to sustain production growth for the next several years.

From an acreage standpoint, it increases our quarter-end acreage position by 65% to over 250,000 acres. None of the properties are subject to pref rights and the leases are held by production or have lease terms that will allow us to protect the acreage at a modest drilling pace.

The acreage also provides upside exposure to other plays in Oklahoma and Kansas such as the Oswego formation and the Woodford Shale, which provides us the same optionality we have with the TMS and the Austin chalk on our existing acreage in Louisiana.

The well costs have averaged $3.7 million per completed well, a relatively low cost that reflects the fact that the Mississippian Lime is located at 6000 feet on the properties being acquired. The type curves indicate EURs of 300,000 to 500,000 BOE per well and the 30-day average IP from Eagle wells drilled this last year was over 655 barrels equivalent per day.

Internal rates of return are well over -- are over 80% based on $80 WTI and Eagle's finding and development costs have been a very competitive $925 per BOE. The acquisition expands our drilling location inventory nearly 60% by adding over 600 gross new opportunities, all of which are horizontal drilling locations. We also think there is significant upside to that figure was down-spacing.

The consideration for the acquisition is $325 million in cash and 325,000 shares of newly issued Series A preferred stock with an additional liquidation preference of $1000 per share. The preferred stock may not be converted before the first anniversary of its issuance. At that time, the shares are convertible at $13.50 per common share. These shares are mandatorily convertible on October 1, 2015 at a price no greater than $13.50 per common share and no less than $11 per share.

We are pleased that the owners of Eagle approved this transaction at a meaningful premium to our current stock price, showing confidence in our existing assets as well as the potential of theirs. Until conversion, the holders of preferred will have special voting rights and the right to appoint one director to our board. The preferred shares will have an 8% dividend. We have the option to pay the dividends either in cash or as additional shares at the conversion date.

There are a number of qualitative aspects to this transaction that make it attractive. We feel we are being appropriately conservative regarding the pro forma projections, the transaction is immediately accretive on a per-share basis on both production and reserves, and even under our assumptions of cash coupon payments, the transaction becomes accretive to cash flow per share in 2014.

The Eagle transaction is expected to close on or about October 1 of this year and will be effective as of June 1, 2012. Keep in mind, however, we will not report production volumes from those properties in our numbers until the fourth quarter of this year. We have arranged committed bridge financing and will now be able to move ahead with the high-yield offering to finance the transaction and enhance our overall liquidity. When we started looking at these properties closely in June, we decided to delay our standalone debt offering until we could determine that the acquisition was a viable transaction so that we could arrange financing for it as well. We know that that created some concern in the market about our liquidity, but we think our go-forward plan now addresses all of those concerns regarding funding of our revised capital plans as well as the acquisition. Tom will go into detail later.

This entire management team believes this is a major step forward in creating a more balanced longer lived reserve portfolio that will support a growing production base with significant upside potential in two exciting emerging oil place. In addition, it is important to note that Eagle's experienced management team and staff will continue with the Company and are invested in Midstates' success going forward.

Now, let me speak to the second-quarter results. Our production volumes were below expectations for the quarter. We grew our oil production by 10% from the first quarter but our overall BOE volumes were down by 4%, basically on a drop of 21% in gas and associated NGL volumes. Steve will cover this in more detail, but the underperformance was primarily due to less than expected results from our development drilling program in our West Gordon field over the past year.

Continued severe decline in the two remaining central fault block wells, which lost 1000 -- 1100 barrels a day quarter on quarter, and a delay in the arrival of our shallow rig for Pine Prairie also contributed to the shortfall in volumes.

Back to West Gordon, at West Gordon, we drilled eight wells in 2011. Based on very encouraging results we have from those wells from initial and early time production, we continued the drilling program of five additional wells in 2012. While we expected steep, early declines from these tight reservoirs, we expected the decline to flatten in six to nine months for our type curves from the historical well results. These wells continue to climb more quickly than expected.

While we remain confident that the field has substantial recoverable oil reserves, the vertical well program is not meeting our return expectations. We are investigating potential causes for the underperformance but meanwhile we have decided not to drill any additional vertical wells in West Gordon. Steve will discuss the potential causes and solutions in a moment.

We do believe that West Gordon is a good candidate for horizontal drilling. On that basis, we are presently sidetracking our AKS 5H1 to target the upper C-- upper Wilcox C sand and will have results there by early September.

Pine Prairie, our largest and best producer, continues to have great results and our other development efforts are meeting our expectations. The Eagle transaction sets close in October, so we will be incorporating their drilling program into ours beginning in the fourth quarter and particularly next year. While we intend to continue developing our existing Louisiana producing fields along with drilling the expansion areas and the option acreage under our new Fleetwood survey as well as our Austin chalk acreage, we will also allocate significant capital to the new Eagle properties later this year.

The Mississippians Play has a longer track record as a horizontal play and Eagle has achieved what we believe are attractive and consistent results from its wells. As a result, we are adjusting standalone capital -- the standalone capital program for the balance of 2012 and reducing the production volumes we now expect.

We invested $207 million through the second quarter of 2012 and now expect full-year Louisiana-only budget to be $365 million. We will drill a total of 70 wells and while that's not a material change in our well count, we have reallocated spending in the second half. For the second half, we now plan to drill 34 additional wells at Pine Prairie, our largest and most prolific field, as well as six horizontal -- or horizontal sidetracks in our Dequincy area. We expect standalone third-quarter capital to be $90 million to $100 million.

Taking into account our revised 2012 budget and the impact of recent production performance I discussed, we now estimate our standalone third quarter production will range between 8100 and 8500 BOEs per day, and we expect a similar breakdown on the production components of oil NGLs and gas as we reported today for second quarter. For July, we averaged 7700 BOEs per day and we are currently producing 8600 barrels equivalent per day.

For the fourth-quarter and full year '13, we will provide additional detail in the next call which we expect to have after the transaction closes. However, we can give you an early indication today of what we are anticipating.

Our 2012 average is expected to range from 9800 to 10,500 BOEs per day which includes the Eagle production in the fourth quarter only. In 2013, as we ramp up drilling from the Mississippian Lime play and continue drilling in Louisiana, we expect a combined capital budget of $400 million to $475 million. About 55% of that budget is expected to be allocated to Louisiana, but we will make final allocations as we see results in the latter half of this year.

In 2013, we will have a broader portfolio of properties so we will better be able to reallocate funds or increase spending in those areas where we achieved our best well results and returns. We believe we can achieve year-over-year production growth of 25% to 35%.

Let me quickly update you on the Clovelly lawsuit. As you recall, we announced that a partial summary judgment in our favor was reversed by the Louisiana Third Circuit Court of Appeals on June 6. We have filed an application for a re-hearing and await their response. We intend to continue to vigorously defend this litigation.

I will come back at the end of the call for further comments, but let's move ahead with Steve giving you some details on what's occurred during the quarter and what to expect for the balance of the year.

Thank you John. Good morning. As shown in this morning's press release, we spud about 20 new wells in the second quarter. 19 of those were vertical wells, one new horizontal drill well, plus one horizontal sidetrack of an existing well bore.

In the core development areas, 11 were in Pine Prairie, all vertical, six were in Dequincy area, five vertical and one horizontal. Additionally, in our expansion areas, we spud three new vertical wells and one horizontal sidetrack.

To give a little color around our drilling program, I will start in the Dequincy area, where we have three core areas -- South Bearhead Creek, West Gordon and North Cowards Gully. South Bearhead Creek in Beauregard Parish is a lower, middle, and upper Wilcox play that has been developed with vertical wells so far. Except the horizontal Massey well that I talked about on the last call, and I will give you an update on that shortly. We've spud six wells this year in South Bearhead Creek and five have been completed. The sixth well is completing now and we expect first production early next month. Of the five wells drilled this year, four are on production and are producing in line with our expectations. One of the wells had disappointing results, but we are evaluating a sidetrack either vertically or horizontally.

We have intentionally drilled step-out wells on the edges of our structure in South Bearhead Creek to delineate pay zones and to set up our horizontal program. We've successfully extended the reservoir limits eastward and plan to drill our first horizontal well on the east side of this structure in the fourth quarter.

In addition to the Wilcox, we are also planning to drill a horizontal sidetrack in the field out of an existing well to the Cockfield. We believe the Cockfield, which is a laterally extensive sand at around 9000 feet, will be an excellent horizontal candidate and we expect to spud that well in October.

To update you on the South Bearhead Creek horizontal Miocene well I discussed on the last call, the well continues to produce above our expectations. It has cumulative production of over 53,000 barrels in just three months and continues to average approximately 630 barrels of oil equivalent per day. This is a great well and it continues to be a strong producer.

On the cost side, in the South Bearhead Creek field, total drilling and completion costs averaged $6.4 million per well last year. In 2012, we have reduced those costs to $4.6 million per well, a decrease of almost 28%. Cost reductions and cycle time improvements have been a real focus area for us and I will discuss further cost reductions in the other core areas.

In the West Gordon field, we have drilled five wells this year. As John discussed, results have been below our expectations on the vertical wells, so we will defer further vertical drilling until we have fully analyzed the results of those wells.

We do, however, continue to believe this area has significant oil reserves, so we will focus on horizontal wells to target those reserves. Currently, we are sidetracking the original horizontal well we drilled last year and targeting the upper Wilcox C sand. Keep in mind the original well had some mechanical issues, but confirmed our ability to drill horizontally in the Wilcox. We expect first production from that well early next month.

Additionally, we have a significant effort underway to address production issues in the field. As John said, the decline curves are not flattening out as expected, and indicate more of a mechanical issue than a reservoir issue. We have found scale and paraffin in our production tubing which obviously inhibits flow, but also makes our artificial lift very inefficient.

We've also run several pressure buildup surveys to evaluate the effectiveness of our fracs. Early indications are that we've lost some frac conductivity which is the reason we have switched to resin-coated frac sand and have controlled the drawdown on our flow backs. As John said, we have elected to slow down vertical drilling until we resolve these production issues.

As I stated on the call last quarter, we continue to pump 80% intermediate strength prop and tail in with 20% resin coated sand. Additionally, we will control the flow back of the AKS 5H holding initial pressure draw-down to less than 20% on the reservoir.

In West Gordon, we expect to drill one more sidetrack out of an existing well this year with an expected spud date in September. As you can see, we are reentering existing wells to test our horizontal theory which helps keep our costs down.

The third core area in Dequincy is North Cowards Gully. We are currently drilling a new horizontal well, our first in that field, which is targeting the upper Wilcox B sand. We expect to complete the well next month. That well is targeting the Wilcox D sand, which has a gross thickness of approximately 120 feet and we believe it will be an excellent producer when drilled horizontally, especially when you see an original oil in place of over 50 million barrels equivalent.

In addition to the upper Wilcox B sand, we are also evaluating several Cockfield horizontal options. As I said earlier, we think the Cockfield could be an excellent horizontal producer.

The other core area I want to update you on is Pine Prairie. As a reminder, Pine Prairie holds 46% of our proved reserves, 64% of our current production and 23% of our potential future locations. As I said in the first-quarter update, we are continuing to drill our deep Wilcox and spud our vertical wells on 10 acre spacing and are moving further into our outboard or off-structure program. In the second quarter, we spud eight wells in this effort. Results continue to be very encouraging and we expect to drill 34 total wells in the Wilcox program this year. All are planned as vertical, although we are currently evaluating the drilling of a horizontal well on the West blank of the field.

The results from our Pine Prairie Wilcox program so far have been very good. The average of our Wilcox wells completed this year are meeting our modeled IP rates of approximately 300 BOE per day.

On the cost side, we have seen significant reductions in our Wilcox drilling and completion costs in Pine Prairie. Total well costs averaged $5 million per well last year but are averaging $3.9 million per well in 2012, which includes the wealth we had issues drilling that I discussed on the last call. Even so, the $3.9 million per well represents a 21% reduction year-over-year, which are very good results any way you look at it.

When you look at the last four wells drilled, the average total cost has been $2.9 million per well, an even more significant reduction of 40% year-over-year. The $2.9 million per well is flat to our top-well expectations, but current wells have 2 to 3 frac stages versus one stage in our type wells. We attribute these cost reductions to improved efficiencies in our drill times, frac costs and location costs -- reduced location costs due to pad drilling.

In our in our shallow Frio and Miocene program at Pine Prairie, we completed six wells so far. As John said, we were delayed in getting a rig to the field until late June due to rig contract or commitment issues which slowed the execution of this program. We are now drilling the ninth well and expect to drill 19 shallow wells this year. These wells are very capital efficient and have higher rates of return due to high IP rates and low drill costs. The expected cost of our Miocene wells is approximately $700,000 per well and the expected cost of our Frio wells, which go slightly -- which go to slightly deeper depths, is $900,000 per well. In total, we expect to drill 53 wells in Pine Prairie in 2012. Of these, 34 are deeper Wilcox wells and 19 are shallow Miocene and Frio wells.

In our expansion areas, we had spud two wells in the second quarter at the time of our May 31 call and spud two additional wells by June 30. One of the wells is the horizontal well in South Fulton that I discussed on the last call. Currently, that well has a work-over rig on it, cleaning out sand and shale that came into the well bore through one of the Packers Plus ports. That well was producing at a rate of 185 BOE per day when the influx occurred. We expect to have the well back on production soon.

In the Mamou expansion area, we had disappointing results on the [Dogaye] well. The well was drilled just offset to three comingled upper Wilcox Conoco-Philips wells on a broad four-way closure. Multiple sands were tested but all produced 100% water. We're currently evaluating the results of the well and the northwest -- northeastern flank of the structure to further assess prospectivity.

The third expansion well is in the Dorald area. We are currently testing the Eunice Canal well in the Sparta sand. We expect results on this well this month.

And the fourth expansionary well is in Pilgrim Church. We are currently completing the Maura well and expect results this month.

So to summarize, in Q3 and Q4, under the revised capital plan that John outlined that takes into account wells we plan to drill on the new Eagle acreage in Oklahoma, we expect to spud 37 more Louisiana wells. 34 are vertical wells planned for Pine Prairie, and one sidetrack of an existing well with 21 in our ongoing Wilcox program and 13 are in our shallow Frio and Miocene program. Plus, we have three new horizontal wells and three horizontal sidetracks planned in the Dequincy area. That is a total second-half capital commitment of about $134 million for drilling and completion activities with 65% of that allocated to Pine Prairie and the balance to Dequincy area.

We currently have four 1000-plus horsepower rigs operating and one smaller rig running in the shallow program. For the balance of 2012, we expect to keep three 1000+ horsepower rigs through the year and into 2013 and run four rigs in Oklahoma.

Our full-year 2012 Louisiana Wilcox expected well count is 70 new wells, of which 66 are expected to be vertical, four are expected to be horizontal. Additionally, along with the 70 new wells, six wells are reentries and sidetracks of existing well bores, of which four of those are horizontal projects.

Our operations team is very excited about adding the Mississippian Lime play to our portfolio. When they joined Midstates, they knew we would be growing well beyond just our initial core area in Louisiana Wilcox. Since the Mississippian Lime as a 100% horizontal play, we look forward to using the knowledge gained from drilling those wells to our increasing use of horizontal drilling in our development areas and expansion areas in Louisiana.

A quick update on our land position in Louisiana. At the end of the second quarter, we had approximately 155,000 net acres under lease or option. This is an increase of 19,000 net acres from the end of Q1.

Also, a quick update on our 3-D surveys. As a reminder, we are shooting a 200 square mile survey in the west Baton Rouge area, and a 72 square mile survey over the South Bearhead Creek field. Both 3-D surveys will be acquiring data this fall with expected initial data set by the end of the year. As we've reported before, we expect the drilling wells off those 3-D results early next year.

Now let me discuss lease operating expenses. Lease operating and work-over expenses totaled $5.9 million for the second quarter, a reduction of $0.5 million quarter-to-quarter. This represents a reduction of 8%. Unit costs dropped to $8.24 per BOE versus $8.59 per BOE in Q1. The majority of the cost reductions were due to the chemical program which was implemented in the second quarter. It increased our efficiency in both performance and cost. Additionally, work-over costs were down slightly compared to Q1.

Saltwater disposal costs totaled about $1.3 million or 21% of total LOE in the second quarter and were roughly flat with Q1. As noted in the Q1 conference call, we plan to drill two new SWD wells in the Dequincy area. One of those wells has been drilled and is being prepared for service and the second well is being drilled now. Once these wells are in service, we expect our need to trunk water in both of our core producing areas to be very minimal which will result in lower operating costs.

In spite of our volume shortfalls in the first half of the year, we have continued to execute our program and have made significant improvements in both drilling and completion costs and LOE. As I said earlier, cost control is a major focus for us.

We have also had success adding to our technical team. We hired 10 technical employees in the second quarter and plan to continue to look for top quality talent. We feel that adding the Mississippian Lime play to our portfolio will have a positive impact on our recruiting.

At this time, I'll turn the call over to Tom for the financial update.

Thank you Steve. Good morning everyone. As during the last call, I don't intend to repeat everything that was covered in the earnings release or go into detailed year-over-year quarterly comparisons. I will focus on the key financial items in the release and provide you with guidance for the third quarter and full year 2012.

First, let me add my comments regarding our excitement around the Eagle transaction. From a finance perspective, these assets will obviously add to our scope and scale, which in turn strengthens the Company's overall financial position. Also, with the transaction, we will execute a capital structure that will enhance our liquidity, which I'll talk more about in a minute.

In addition, Riverstone taking equity at a significant premium to our current stock price speaks volumes to the confidence our new partner has in both the (inaudible) the transaction as well as Midstates' overall business plan and team.

Our overall financial result of $0.03 per share of adjusted net income was ahead of consensus and $0.48 per share discretionary cash flow was in line, but our total production volumes were below expectations, as we've discussed. We likely exceeded some estimates due to a higher percentage of total production that was oil. Our realizations were slightly better than LOS and our costs were on the low end of guidance.

Adjusted EBITDA for the second quarter totaled $32.8 million and we reported a GAAP net loss of $112.4 million or $1.85 per share. The differences were from the unrealized gains on derivatives and the IPO related tax accruals, which I will discuss more in a minute. We presented the reconciliations of net income to adjusted EBITDA, and adjusted net income in the supplemental information in the earnings release that you have.

In the first quarter, we reported the mix of production as 54% oil, 17% natural gas and 29% -- or excuse me, 17% liquids and 29% natural gas. In the second quarter, we improved that mix with our production being 62% oil, 14% NGLs and 24% natural gas. We returned to normal mix during the quarter and expect to continue to be about 60% to 65% oil, 10% to 15% NGLs and the balance in natural gas for the third quarter of '12.

John has already reviewed production volume expectations for the third quarter and given you a preview for the full year '12 as well as 2013 volume, so I won't go into that. Midstates' average realized price per barrel of oil before realized derivatives was $107.57 in the second quarter of '12 compared to $111.21 in the first quarter. Our contracts for the sale of oil to the local refineries provided that we pay the LOS differential to WTI on about a 30 day delayed basis. As a result, you may recall that our realizations in the first quarter were lower than LOS posted prices during the quarter as prices were rising month over month. In the second quarter, as you all well know, prices fell month over month so we enjoyed the benefit of that lag during the quarter. We will continue to have that one-month lag in the LOS differential affecting our future pre-derivative realization. Our realizations also reflect a little bit over $2 a barrel in transportation costs for trucking.

Natural gas was $2.27 per MCF. That compares favorably to the (inaudible) average during the quarter due to location and quality of our gas. We are also processing the majority of our gas production and the price realized as far as NGLs averaged $39.83 per barrel.

The earnings release also included detailed information on the hedges we now have in place on our crude oil production. We did not add any positions during the quarter but we did convert our Brent-based hedges to LOS hedges to eliminate any basis risk between our cash prices and our hedges. We currently have about 4200 barrels per day hedged for 2012 at an average price of about $105 a barrel, and 4700 barrels per day hedged at an average price of around $101 a barrel in 2013. We will post the latest hedging information on our website along with our guidance summary. As we look at it today, our hedging target continues to be around 50% (technical difficulty) the next couple of years. The Company does not have any hedges in place on its natural gas liquids or natural gas production.

Let me now go through expenses. Steve already covered LOE expense, so I won't go into details of that. But going forward, we expect LOE rate per barrel to continue to go down as we add more wells and production while our absolute costs rise at a slower pace. For the third quarter, we expect total LOE to be in the range of $8.25 to $9.25 per barrel.

Severance and ad valorem taxes totaled $6.3 million for 2012's second quarter compared to $5.4 million in the first quarter. That equates to about 10% of oil, natural gas and NGLs sales revenues before derivatives in the second quarter compared to about 8% for the first quarter. Ad valorem taxes were $100,000 lower in the second quarter, so the increase was in severance taxes which is primarily due to the production mix with higher oil production and lower produced natural gas in the second quarter compared to the first quarter.

Louisiana's severance taxes for oil are applied as a percentage of the value realized with the top rate at 12.5%, while for natural gas the severance taxes are applied at a flat rate per MCF produced. So with the increase produced in oil sales this quarter, the severance tax rate increased. For the second quarter, I would use about 10% to 11% of revenue.

our second-quarter G&A expenses were $4.9 million, or about $6.89 per BOE, compared to $6.1 million or $8.05 per BOE in the first quarter. Cash G&A totaled $4.3 million and non-cash compensation totaled $600,000. We expect our third-quarter G&A to be in the range of $8 million to $9 million, of which about 12% to 15% will be non-cash compensation. The increase primarily reflects our head count growth.

Total cash operating costs which include lease operating and work-over expenses, severance and ad valorem taxes and the cash portion of G&A administrative expense, declined to $22.90 a barrel from $23.78 a barrel in the first quarter.

Depreciation, depletion and amortization expense of $27.9 million was essentially unchanged from the first quarter of 2012, while the DD&A rate for the second quarter of 2012 was $38.77 per barrel compared to $37.22 per barrel in the first quarter. You can expect between $38 per BOE and $39 per BOE in the third quarter.

Total interest expense was $1 million for the second quarter compared to $1.7 million in the first quarter. The decline was primarily due to the decrease in the average outstanding balance under the revolver facility which fell from $235 million at the end of March to $151 million at June 30, 2012 as a result reduced interest expense associated with the $65 million in preferred units that we paid off in the IPO.

We capitalized $1.7 million in interest to unproved properties during the second quarter.

As we discussed with you last call, prior to the corporate reorganization, in connection with our IPO, Midstates was an LLC company and did not pay corporate income taxes. With the corporate reorganization the Company became a taxable entity in April and was required to record a charge against income for the differences between tax and book basis of our assets and liabilities as of that date. As a result, in the second quarter, we recognized an initial non-cash deferred tax liability of about $150 million and a corresponding amount as tax expense in our income statement.

We also recorded income tax expense during the quarter of $19 million related to income earned subsequent to April 25, the date that the corporate reorganization occurred. Our estimated effective tax rate for the year will be about 50%, which represents the statutory rate for federal tax and the estimated effective state income tax rate, as well as our inability to use losses incurred prior to the IPO to offset post-IPO earnings. We do not expect to have a cash income tax liability in the foreseeable future.

Let me now review our liquidity position with you in light of the impending transaction. As you will recall, we priced a bit below our expectations in the IPO, and in turn that hampered our original liquidity expectations coming out of the offering. In addition, over the last several weeks, we have been working feverishly on the acquisition which caused us delay in terms of executing a standalone liquidity solution as well as any communications regarding that. Now that we have a clear path to close the acquisition, we've developed a capital structure that we believe will position us to handle the acquisition as well as provide for capital for combined assets going forward through 2013.

So let me try and outline our capital structure now. As you know, our current standalone borrowing base facility is $200 million. In July, we drew $20 million which brought our current balance on the facility to around $171 million. We have secured an increase in that facility to $235 million in advance of the close of the transaction. Note that increase is not contingent on the consummation of the acquisition. In addition, upon the close of the transaction, as part of the committed acquisition financing, the borrowing base will increase to $250 million.

Also, in association with the transaction, we secured $500 million in committed bridge financing. This bridge is available to fund the cash portion of the transaction and provide fertile liquidity, but our plans are to access the debt markets prior to closing the transaction. As I mentioned before, this collective capital structure is expected to give the Company sufficient liquidity to fund its development program through the end of 2013.

Thanks for your attention this morning. Now let me turn it back over John.

Thanks Tom. Let me make just a few more closing comments. We really believe this transaction we announced today is both strategic and transformative. Midstates going forward will maintain its liquid-weighted reserve base and drilling portfolio with combined assets. We're very excited to have taken the first steps in growing into a multi-play company that fully exploits the expertise we have in our technical and management teams. We will continue to look for complementary additions to our portfolio if they can compete with our drilling portfolio.

While we may move at a more -- a bit more measured pace in our Wilcox play with the addition of Mississippian Lime, both of those areas provide us with significant running room for additional production reserves. We will be a stronger company with a longer reserve life and increased critical mass with a more balanced risk profile -- risk drilling profile. Scale makes a difference in our business.

We also believe that our go-forward financing plan addresses our liquidity needs quite effectively.

One more note to highlight is you have a Midstates staff and significant large holders with First Reserve and Riverstone and Eagle team that are closely aligned with you, our public shareholders.

In closing, we recognize we've given you a lot of information today. We will be participating in the Barclays conference in early September as well as several other meetings during the next few months. We are always available to talk or meet with you to discuss any further details that we have announced today. With that, I'll turn it back to Al.

Okay Felicia, we will be ready to take questions and we ask that you limit your questions to one and a follow-up. We are ready to go.

(Operator Instructions). Brian Singer, Goldman Sachs.

Good morning. Beyond that you're pursuing horizontal opportunities in both the Wilcox and the Mississippian, can you talk to the geologic similarities between the two plays relative to the expertise of the Midstates team, in other words to a degree how important is the one-year overlap of the Eagle team to your ability to execute longer-term?

First of all, it's very important to have that overlap of the Eagle team. They have been highly effective in developing this play and we're certainly pleased that they will be working closely with us, certainly through this transition period, and we hope for a longer period of time ultimately. In both cases, we are working with what we would call tight reservoirs that typically require fracture stimulation and we believe both obviously in the case of Mississippian Lime, it works quite effectively with horizontal multistage fracing, and we believe the same logic applies to the Wilcox intervals.

Got it, okay. And then when you think about the next couple of years, do you see further meaningful acquisitions in new plays or in the Mississippian? And would you acquire more in the Wilcox or would you rather wait until additional well results give you more confidence in aerial extents and horizontal potential as you are kind of shifting to more with your cut backs reductions?

As we always say, we try to look at each potential opportunity and compare it against the portfolio we have in place at the time. So, I guess it's a little hard to just kind of lay out a number on that, but certainly we've got a very significant position in the Wilcox already. The Fleetwood survey which we are shooting now is ultimately 120,000 acres under that survey. So we've got about 60,000 of those acres already under option, and we feel like we are pretty well taken care of for acreage in that play at the time. But obviously if the right opportunity came along, we would be very interested in taking it.

Great, thank you.

John Herrlin, Societe Generale.

With respect to the deal, could you give us a little bit more of the backlog background? Was this a brokered deal, how did it come about, and were the reserves externally engineered?

Curtis, do you want to -- we've got Curtis Newstrom, our Business Development Vice President here. I'll let him run with that.

Yes, the reserves are actually a roll forward of a third-party audited reserve report that was done at the end of last year, and so we've updated that. It has not been done -- it rolled forward by a reserve auditor at this point but that's ongoing and we should have that information before closing. And the deal was brought to us by Evercore Partners, and it was an option a while back, and had not been actively being pursued, and so we started talking to them I guess about three months ago, and things have rolled forward since then.

Great. The next question for me is for the horizontal well that's producing so well, the Massey well, is that on pump or is it flowing naturally?

We are giving it a little gas lift, but it's pretty much flowing. We goose it a little bit with some gas lift gas.

Okay, thanks. That's it for me.

Leo Mariani, RBC.

Just a question about the horizontal wells going forward. Obviously, you guys are talking about sidetracking a number of wells. What type of lateral length are you targeting there, and what are you thinking about in terms of costs for those side tracks?

Steve, do you want to take that?

Lateral length will range from probably 2500 to 3500 feet. Costs depending on where it is and number of frac stages will be between $5 million and maybe $7.2 million. That's a wide range, but these wells have different lengths, and we'll frac them typically with the Packers Plus system.

And what zones are we targeting here? Are these just the Wilcox there?

Real target Wilcox C, Wilcox B, upper Wilcox C and B and we will target the Cockfield in a couple of areas.

Okay, thanks.

Brian Lively, Tudor Pickering.

This is Brian. Just a follow-up question to Brian's earlier strategy type question, but as you guys look out to doing more acquisitions in the future, could you guys just discuss what is the approach? Are you looking at is it basically where the best deal is? Are you looking to build onto have more of a concentration? The question is are we going to see another MS Lime deal, are we going to see a Permian deal? How do you think about acquisitions?

I think first of all, we're going to see if we can swallow this one first. But I grew up at Apache, and we used to always say that if we could add some more assets in the area where we are active that's always the best choice. But we also knew it was necessary for us to get some diversification in our portfolio. So I wish I could point to something that makes sense, but we will be just looking at opportunities as they come along. And if they compete with the portfolio we've got in front of us, then we'll go for them.

My follow-up is just on the LOE guidance, you guys talked about the LOE, unit LOE going down over time, but as you start exploiting the MS Lime given the high water cut, do you expect your LOE trend up over time versus down once that becomes a bigger piece of the overall production base?

You're pretty familiar with Mississippian Lime, and I guess what I would say is that what Eagle has done is they've got basically their saltwater disposal infrastructure in place and the water is typically pipelined to water disposal wells that take the water on vacuum. So we don't really think that the Mississippian Lime's wells in spite of their high water cut will increase our lifting cost anything dramatically.

Thanks John.

Adam Lawlis, Simmons & Co.

Hello guys. I was going to see if you guys could give us some kind of color range of how you are internally valuing today the preferred component of acquisition.

Well, I think we've got it kind of laid out there, and I recognize it's not the easiest thing for you guys to put any numbers on. But the structure is fairly clear. This is convertible stock, and the lowest it can convert at is $11 per share and the highest it can convert at is $13.50 a share. Obviously, the 8% coupon is worth something as well. So you know what our stock price is today, so I don't know that I would be wanting to give you a message on what I think it's worth.

Okay, that's fair. Thanks. Then switching gears, kind of on some of your acquisitions on acreage acquisitions and other Gulf Coast tertiary trend, what are your current acreage costs over there?

Go ahead Steve.

We are running, and we've added acreage in Austin chalk and the Fleetwood area, which is the West Baton Rouge area, and it's typically running about $150 to maybe $300 an acre. And those are three-year paid-ups with three-year kickers on top of those.

Great. Thanks. The competitive environment in there I guess, how -- could you speak on that? Do see more competitors getting in the play or leaving the play or kind of flattish relative to last quarter?

I don't have our land VP with me, but he indicates to me that our guys are seeing more people in the courthouse in the areas we are interested in. But we still see very little pressure on getting the acreage we would like to get in Louisiana.

That's all I have. Thanks guys.

Chris McDougall, Westlake Securities.

Thanks a lot for taking the question, and congrats on the acquisition. You talked about the saltwater disposal wells going into your current acreage, and reducing costs. so what is your expected timing for that, and how much in kind of dollar value should we expect for cost reduction?

The timing is the first well has been drilled. We are planning to drill two; the second one is drilling now. I don't know if I can put an exact number on it, but saltwater disposal costs run about 20% of our total LOEs. So I would expect to see 5% to 10% of that go away as we stop trucking water.

Okay. Perfect, thanks. And then on the overall well costs, you had some pretty good reductions, like 20% year-over-year. Should we expect those to continue going forward, or what sort of pace should we expect? Assuming kind of a constant mix? I know between the horizontal and vertical mix there's a significant cost severance and such.

I don't think we will see year-over-year numbers like that. I can tell you that cost is a very significant focus for us. And John has talked about the team that we've built here, and all of these guys and gals have backgrounds with companies that have been low-cost producers. So it's definitely a focus for us.

yes, it is hard to make the same kind of steps each year, but obviously a number of things are happening that are allowing us to get those numbers down. Obviously, as you learn more and more about the areas you're drilling, you come up with better ways to do it. But a lot of it is around the cycle time that Steve has really pushed hard on in our organization. So we'll continue to push those. I wouldn't expect another 28% drop, but we'll be trying to get as much as we can.

Thanks a lot guys.

Don Crist, Johnson Rice.

Good morning guys. On the last call, you talked about your two horizontal wells that were still rising in flow rates. Can you give us an update as to where those peaked out?

Yes. Just to give you a sense, Steve, obviously the one we're most proud of is that Musser-Davis 33H which Steve talked about. That well has been holding flat at 600 to 625 barrels a day right from the beginning. And that's the rate it was making when we talked to you last, so Steve told you it's already made 53,000 barrels and continues to come at very solid rates. The other well we were on he described as well that well had come in at 350, 400 barrels a day. It declined down and was producing at 180 to 200 barrels a day, as Steve described. And then we lost it, and that was the fishing job he was describing where we were trying to clean out shale and sand out of the well bore. So we'll have to see what that does so we can get it back on.

Okay. Just one other general housekeeping question. Your G&A came in quite a bit below guidance for the second quarter. What was the main driver behind that?

The Board cut my pay. Somebody help me with that. So it was a significant change in the incentive compensation metrics.

That's all I've got. I'll turn it back.

I was kind of serious when I said that.

(Operator Instructions). Brian Lively, Tudor Pickering.

I just had a horizontal follow-up. In the West Garden field where he talked about the vertical wells declining faster than your expectations, and then subsequently doing some -- it looks kind of like some build-up tests to look at mechanical scan, etc., just wondering what do you think you gain from doing the horizontal wells that would limit that? Is it a -- do you think you're overdrawing down the formation or just why do horizontal wells potentially change some of the damage or fracture issues that you've seen?

I guess a number of things. One, when Steve described we had scale buildup, one of the things that's become evident, at least in West Gordon, is that combining a number of sands together that have varying water quality in them is actually creating some scale issues that we are not expecting.

Now, Steve has added a new production manager about three months ago, and he has been all over that. So obviously, we can control that some with chemicals. But we hadn't been doing that, so we found a lot of scale buildup that we are having to deal with now. Obviously, if you went horizontal, you would only been one interval, and therefore not see that. So we are doing a combination there on that piece.

The other point Steve is making very strongly is ever since he has come in here, he's said you need to produce these back at a little slower rate. We've got solid evidence that we are producing frac sand back, and that was his point about tailing in with resin coated and keeping our flow-backs controlled. So Steve, do you want to add to that? I probably took all your thunder but --

No, I think you captured it, John. What I can say is on the AKS 5H, which is the West Gordon horizontal sidetrack we have going now, when we drilled that well initially, we kind of bounced up and down through the sand trying to chase it and we ended up only getting three frac stages off. We are about 1500 feet in-zone right now of which at least 98% of that is in the target sea sand. So, I'm a lot more optimistic the way the drilling on this one is going.

Makes sense.

John Herrlin, Societe Generale.

Yes, hi. I think one more on West Gordon, any reserve loss there?

John, we are not ready to talk about any reserve loss there because we still think we have a pretty good chance of doing some remedial work that will recover this. Curtis, we had at the end of last year about 5 million barrels booked to West Gordon, so any change would be minor if indeed we have to.

Thanks John.

Jeb Bachmann, Howard Weil.

Just a couple of quick ones for me. First, John, do you guys anticipate being able to hold on to any key Eagle employees past the one-year lockup?

I guess we'll have to talk to them, but we would sure love to because they have done such a great job on the assets and building this operation they have. So, you'd probably need to talk to them. But I hope, given we've got a year to kind of work with them and show them what a good organization this is to be part of, that hopefully we can keep them.

Then last one, I might've missed this on the call, but could you identify the Mississippian counties that this acreage is located in?

Yes. We are in Woods and Alfalfa County, which is I know you keep track of the Mississippian Lime, that's kind of a heart of the play. You see a lot of activity there from Chesapeake and SandRidge as well. Eagle has been kind of the third most active player in this play, and continues to be one of the leading developers.

Great, thanks John.

There are no further questions at this time. I would like to turn the conference back over to Mr. Petrie for any closing remarks.

I'd like to say thank you to those of you that joined us today. We will give you some more information. We felt a little bad about not being able to come out and talk to you a little bit more over the last kind of month, month and a half. But as you can see, we were deep into discussions on this acquisition and didn't feel it was appropriate to put half the information out. So, I appreciate your patience and your support.

And as a reminder, we do have the slides on the website today. Thank you for joining us.

Thank you. This concludes today's Midstates Petroleum second-quarter earnings conference call. You may now disconnect.