Mariner Energy, Inc. Q3 2009 Earnings Call Transcript

| About: Mariner Energy (ME)

Mariner Energy, Inc. (ME) Q3 2009 Earnings Call Transcript November 6, 2009 11:00 AM ET

Executives

Patrick Cassidy – Director of IR

Scott Josey – Chairman, President and CEO

Cris Sherman – VP, Chief Accounting Officer

Analysts

Neal Dingmann – Wunderlich Securities

Michael Jacobs – Tudor, Pickering, Holt

Richard Tullis – Capital One Southcoast

Brian Singer – Goldman Sachs

Phil Dodge [ph] – Towey Brothers Investments [ph]

Nicholas Pope – Dahlman Rose

Kristal Choy – Raymond James

Jeb Armstrong – Calyon Securities

Scott Hanold – RBC Capital Markets

Operator

Good day, ladies and gentlemen and welcome to the third quarter 2009 Mariner Energy Incorporated earnings call. My name is Stephanie and I will be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question and answer session. (Operator instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Patrick Cassidy, Director of Investor Relations. You may proceed, sir.

Patrick Cassidy

Thank you, Stephanie. Good morning and welcome to Mariner Energy's 2009 third quarter earnings conference call. Today's call is being webcast, and a replay will be available on the Mariner's Web site following this call for the next ten days.

This is Patrick Cassidy, Director of Investor Relations for Mariner. On the call today are Scott Josey, Chairman, Chief Executive Officer and President of Mariner Energy; and Jesus Melendrez, Chief Commercial Officer and acting Chief Financial Officer; and Cris Sherman, Vice President and Chief Accounting Officer.

The news release announcing the company's results was issued yesterday and is available on our Web site. Today's call, Scott will provide opening remarks and an operational update. Cris will discuss the company's overall financial performance, and you are welcome to ask questions after we complete our prepared remarks. Before Scott begins his review, please note a caveat about non-GAAP measures and forward-looking statements in today's presentation. Our press release issued yesterday reconciles the non-GAAP measure of operating cash flow.

Today's presentation may include forward-looking statements reflecting Mariner's view about future events and their impact on company performance. All remarks, other than statements of historical fact that address activities that Mariner assumes, plans, expects, estimates, or anticipates, and other similar expressions such as will, should, or may occur in the future, and including our guidance, are forward-looking statements. Such forward-looking information may involve risks and uncertainties that could affect the company's operations and financial results, causing our actual results to differ from our forward-looking statements. These risks and uncertainties are described in Mariner's filings with the Securities and Exchange Commission, including our Form 10-K as amended for the year ended, December 31st, 2008.

The SEC generally has permitted oil and gas companies and their SEC filings to disclose only proved preserves. Mariner uses the terms prove, probable, possible, and non-proved reserves, reserve potential, or upside, or other descriptions of volumes of reserves, potentially recoverable, that the SEC may prohibit in SEC filings. These estimates are by their nature more speculative than estimates of proved reserves, and accordingly are subject to substantially greater risk of actually being realized by Mariner. Information disclosed during this conference call does not constitute an offer to sale or a solicitation of an offer to buy any Mariner securities.

Now, I will turn the call over to Scott Josey.

Scott Josey

Good morning. Before I begin my prepared remarks, I want to welcome Cris Sherman, our Chief Accounting Officer to the team and to the call. Chris joined Mariner last month, bringing nearly 25 years of energy industry experience to the company. He has been a Chief Financial Officer, Chief Accounting Officer, and a partner in a professional services firm focused on the energy industry, among other professional leadership roles, and we are glad that he's here.

I also want to welcome to the call Jesus Melendrez, our Chief Commercial Officer and acting Chief Financial Officer. Jesus has been a key part of our success. He is well-known by our bank group and has played major roles behind the scenes in our financings. He negotiates our transactions, heads our marketing, strategic planning, hedging, and IT. We have worked together for many years, and I have complete confidence in his counsel. With Jesus and Cris, the transition has been seamless.

I have a number of items that I want to discuss and I will start with production. Our production for the quarter was 33.3 Bcf equivalents, averaging 365 million cubic feet equivalents per day, up slightly quarter to quarter. Deepwater comprised approximately 47% of our third quarter production, with 39% from the Shelf and 14% from the Permian basin.

We had increases in production in the Deepwater and the Permian operating areas. Overall, production was below our original expectations due to a variety of unexpected scenarios, all of which materialized in the third quarter, all of which are explainable, and virtually all of which have been resolved or are in the process of resolution.

In the third quarter, we experienced a series of pipeline shut-ins, delays in production from outside operated projects, as well as delays in operated projects. Seemingly, the proverbial, when it rains it pours. The primary contributor to the production shortfall was construction delays at our Vermillion 380 project on the shelf. As you may recall, Vermillion 380 was damaged in Hurricane Ike, and the restoration of the facilities is taking a little longer than we originally expected. Vermillion 380 is an impactful project, expected to produce 3,000 barrels of oil equivalent per day to 4,000 barrels of oil equivalent per day net to Mariner. When projects of this magnitude are delayed late in the year, our annual production and guidance are going to be affected. Nevertheless, production should be back on track by year end, and we are currently producing approximately 360 to 365 million cubic feet equivalents per day.

It is probably worthwhile to discuss our operating philosophy. 2009 has been a challenging year, in which we faced uncertain financial markets and significant decline in natural gas prices. Our emphasis this year was on creating liquidity. We strive to manage the company dynamically, adapting to market conditions. We do not manage the company solely for the sake of production.

We manage it to generate greater return, cash, and cash flow per share. If we had sought just to increase production, we could have pursued several recompletion and drilling projects in the shelf and on shore earlier in the year. But we delayed those projects because we felt we would receive lower cost, and did not want to accelerate natural gas production in a low commodity price environment. The delay has been prudent, although it did reduce the cushion to absorb future production shortfalls like we experienced in the third quarter.

We have recently commenced some of those projects at lower cost. We are experiencing excellent results, which I will discuss later, and expect to receive higher commodity prices than we would have received had we pursued them earlier in the year. Also, despite lower production and lower natural gas commodity prices, we project that we are within reasonable range of our cash flow goals, which in our view more than mollifies a production shortfall.

I'll now comment on our exploration program. We started off the year with several successes, then we had consecutive dry holes at Arden, Corr Dodge [ph], Sherwood and Tiger. On Corr Dodge and Sherwood, we received promotes, and our interest at Tiger was relatively small. The total exposure to Mariner for those three dry holes, Corr Dodge, Sherwood and Tiger was only $24 million, pretty small dollars relative to the potential.

Our exploration program historically is around 60% successful. Last year, it was 80%. As I have said many times, when it exceeds 60%, I do not necessarily expect it to last, but also when it falls much below 60%, I do not expect it will last either. And we believe we will be in a range of 50 to 60% success for the year, possibly better, before the year's done. It is probably worth noting that we are drilling considerably fewer wells this year in the Gulf of Mexico which can distort statistics.

As evidenced that dry hole streaks do not last, we've had good discoveries recently in the Deepwater at Wide Berth and on the shelf SMI 10. Wide Berth, located at Green Canyon 490 was a prospect we attempted to acquire in a recent lease sale but lost to a higher bid. We were able to farm into the prospect, and have a working interest of 56%. It was drilled as a 50 Bcfe to 100 Bcfe prospect. The discovery well encountered 130 feet of net hydrocarbon pay in a single zone and appears to be in the midpoint of the reserve target range.

We are currently assessing development options, which include drilling another well on the block, and possible joint development with a nearby discovery, and we hope to have it online within the next 12 months to 18 months. SMI 10 on the Shelf was one of the projects we originally planned to drill earlier in the year, but delayed with the expectation of lower cost. The well has encountered 87 feet of pay and has potential reserves of 8 to 10 Bcf equivalents and should be online by year end.

Other highlights are as a result of our relationship with Anadarko, which we appreciate. We consummated an eight-block trade on blocks in the Heidelberg area; the trade expands our interests in a prolific ZIP code and gives us a position in a drill-ready high potential, Middle Miocene prospect at Lyell, located at Green Canyon 550 and 551. It also affirms our acreage and prospect position by a top exploration company.

In a separate trade with Anadarko we assumed operations at Balboa, which was an Anadarko discovery at East Breaks 597, approximately six miles from Boomvang. We estimate the Balboa has gross potential reserves of 7 to 8 million barrels equivalent, and we will have a 50% working interest. We've completed the discovery well, and are designing the subsea tieback. Our current schedule is for initial production to occur in approximately 12 months. Possibly it could be sooner.

The acreage drop in the Balboa trades were non-cash trades with Anadarko. Additionally, we were recently contacted by Anadarko to participate in the Lucius prospect in 7,500 feet of water on Keathley Canyon 875. Lucius is a subsalt Miocene [ph] play with estimated pre-drill gross reserves of approximately 100 million barrels equivalent.

Offsetting the significant discoveries made recently by Exxon, ENI and Petrobras at Padria [ph], we will have a 16.7% working interest in this high potential prospect. This would be a record-setting well for Mariner, as it's in the deepest waters we've drilled, exceeding our Aconcagua discovery in 1999 at Mississippi Canyon 305, which was in 7,100 foot water depths.

After Lucius, the rig is expected to move to Green Canyon 903 to commence drilling on Heidelberg 2. This well is designed to delineate the lateral extent of the lateral extent of the reservoir found in the discovery well in the Middle Miocene as well as the test the Lower Miocene.

With the results of Heidelberg 1 and 2, we expect better able to assess along with our partners, the reservoir size, determine of development concept and sanction the project. We hold 1.8 [ph] working interest in Heidelberg and adjacent blocks.

For the rest of the year, we expect to drill the Crock [ph] prospect, at DeSoto Block 4 operated by Murphy, which is near the Dalmatian discovery at DeSoto Canyon Block 48. We'll have a 12.5% interest in Crock.

Also, at Swordfish, Noble, the operator is preparing to sidetrack one of the wells targeting additional pay, and we have a 15% working interest there. Later this month, we will test a deeper exploration target at SMI 150.

Data from shallower zones in this well should help resolve the questions about the mechanical problems we experienced in two of the three wells that we attempted to bring online earlier this year.

Moving to the Permian, we have ramped up our activities as a result of lower costs and higher oil prices and the increase in capital spending we announced on our last call. I will start with providing more color on our Deadwood project.

Today, we drilled 11 wells, and expect to drill several more before year end. These wells costing approximately $1.3 million gross are encountering six pay zones to eight pay zones, and are expected to average approximately 150,000 barrels equivalent per well.

We have 3D coverage over a portion of the field and are preparing to shoot 3D seismic over the rest of the field soon. We should further assist in our evaluation. We are pleased with the results thus far. With 31,000 net acres, we believe this property has significant reserve potential to the company.

Similarly, we have 5400 net acres in a Scottish Rites field, targeting the Sprayberry, Dean, Wolfcamp and Cline [ph] formations. This is an old abandoned field that had no production when we the leased the position, but believe to not been fully exploited on its previous 120 to 160-acre spacing.

We've drilled 21 wells to-date, since May 2008 with very solid results. These wells cost approximately $1 million to $1.1 million to drill and complete and are expected to average approximately 110 to 120,000-barrels equivalent per well and we believe that it can be down spaced to 40 acre spacing.

Deadwood and Scottish Rites produce approximately and 70% oil and about 30% natural gas before processing. We currently have four rigs running in the Permian, and expect to steadily ramp up the activity there. Additionally, we plan to spend significantly more capital in the Permian next year.

On the unconventional side, we are actively working on conventional opportunity, our deal flow has been robust, and this week we were the high bidder for a small portion in the Bakken at the state lease sale, which we expect to close next week, and I believe we will have other unconventional projects to discuss with you here in the very near future.

We expect our capital spending for the year to range from about $575 million to $600 million, which will be within our operating cash flow expectation. On insurance recovery, to-date, we have collected approximately$68 million, and could receive an additional $50 million to $75 million by year end.

Our insurance receipts coupled with operating cash flow could range from $700 million to $725 million, contributing significantly to our liquidity. By year end, our revolver could be virtually undrawn.

In summary, despite the production short fall, we expect to have a very solid year. We expect to spend less than half of what we spent last year, and yet achieved good production growth, strong cash flow, excellent liquidity, and we will have a broad diverse opportunity set.

With that I will turn the call over to Chris.

Cris Sherman

Thank you, Scott. As Scott mentioned, even with the production deferrals and project delays, Mariner had several notable operational achievements during the third quarter. Further, the company continued to achieve strong cash flows, continued to strengthen its balance sheet and paid down its revolving credit facility by $75 million, providing the company with $730 million, at September 30, 2009 and availability under it’s recently affirmed $800 million borrowing base.

As we look at the quarter, however, the company did incur some non-recurring hurricane-related lease operating expenses and certain other higher than anticipated G&A expenses that negatively impacted results. These items total approximately $15.4 million on a pretax basis and I will provide some detail around these items.

Revenues for the third quarter of 2009 were approximately $227 million, down 28% from third quarter 2008 revenues of $318 million. This quarter-to-quarter decrease is primarily attributable to lower realized prices. Our realized price for natural gas during the third quarter 2009 averaged $5.39 per Mcf, a 49% decrease as compared to $10.50 per Mcf for the same period a year ago.

Our realized oil price per barrel averaged $73.15, down 21% from $92.97 during the third quarter of 2008. NGL sold for an average realized price of $36.85, as compared to 61. 05 last year, a 40% decrease.

These realized sales prices reflect net hedging gains of $55.7 million, during the period from Mariner's hedging program. Turning to expenses our lease operating expenses for the third quarter was $65.3 million or $1.96 per Mcfe. This includes $7.8 million, or approximately $0.23 per Mcfe and non-capitalized, non-recurring hurricane repair expenses some of which we expect to get insurance reimbursement in future periods.

For the same period last year, we also reported LOE of $65.3 million, which equated to $2.41 per Mcfe. Last year's per Mcf unit cost results reflect a lower volumes realized due to short in production during and following Hurricane Ike.

Our general and administrative expense for the quarter was approximately $18.9 million, or $0.57 per Mcfe, up from $11.6 million and $0.43 in the third quarter last year. The increase in quarter-to-quarter G&A expenses is due in part to an increase in our non-cash share based compensation expense of $1.7 million.

The G&A increase also reflects a period-over-period increase in salaries, wages and professional fees, of $3.1 million and increase in litigation reserve of 800,000, and an increase of approximately $2 million related to field overhead G&A expenses.

Depreciation, depletion and amortization expense decreased during the third quarter to approximately $106 million as compared to $114 million for the third quarter of last year. This decrease is primarily the result of a significantly lower DD&A rate per Mcf due to the ceiling test impairments we recorded at December 31, 2008 and at March 31, 2009.

We reported net income of $4.2 million for the three-month period ended September 30, 2009, which e equates to $0.04 on a diluted per share basis. This compares with net income of $64.7 million, or $0.73 per diluted share for the same period last year.

In closing, our third quarter earnings were negatively affected by the hurricane-related lease operating expenses and the other miscellaneous items of G&A, I noted. However the company's assets continue to generate strong cash flows with the company generating approximately $404 million in operating cash flow for the nine months ended September 30, 2009.

This concludes our prepared remarks, and now Scott and I will open up the line for questions.

Question and Answer Session

Operator

Thank you. (Operator instructions). Our first question comes from the line of Neal Dingmann with Wunderlich Securities. You may ask your question, sir.

Neal Dingmann - Wunderlich Securities

Scott you mentioned the budget for next year it looks like it will be down. Can you give us color as far as maybe at the same time the question you said that Spraberry or the Permian would ramp up? Trying to get a sense of the breakdown of the budget mix or just on a percentage basis and then obviously like your competitor I know Pioneer has some pretty ambitious plan to ramp up their Spraberry. Is your going to be as near as ambitious?

Scott Josey

Sorry if there was a misunderstanding. Our budget for next year we have not put that together yet. I know you know and as we’ve said before the way that we do our budget is that we strive to live within our cash flow. We are in our budget process as we speak. We will be meeting with our Board here shortly, and at that time, probably about early to mid-December, we will have a call with, with the market to bringing up speed on where we stand. What we had done this year was it, as I said earlier in the call was we were focused on liquidity, and we try to keep our capital spending well below our cash flow.

We have the ability to do and then just later in the year we decided to increase our spending which we announced on the last call and that those dollars $40 million to $50 million went to two places. It went into the shelf, where we were (inaudible), where we have had success, we are going to drill the well at SMI 150, here shortly. And then we began ramping up our activities in the Permian. This year, for 2009, we spent less in the Permian than what I would have liked, but with a focus early on of trying to create as much liquidity as possible, it was really an easy place to cut some capital, and also in the Permian, as well as in other areas, we were expecting costs to come down and we are willing to wait until that occurred. Now the costs have come down and commodity prices have come up. We have begun spending more dollars and I can see that continuing into 2010 and hopefully beyond.

So, we like the position we have got there. We like what we have it on the existing asset base, we like what we feel like we have developed there at Deadwood, we have got other acreage positions at and Blue Plate and others that will begin to explore and exploit in 2010. So, I see our activity in the Permian ramping up significantly. As far as the other areas, I need to wait and see where we stand on our budget process, but our capital spending I suspect will be around what our, where our cash flow is, and I would think it would be at least what it was this year and hopefully more.

Neal Dingmann - Wunderlich Securities

And then when you’re modeling this budget, going into next year, what is your thoughts on service cost as far as rigs and incompletion and everything as far as both onshore and then on offshore deep and shallow. Where they are now versus what you think they will go in '10?

Scott Josey

We did see costs come down, a fair amount in the Permian. We have seen them come down in the shelf. And I suspect that they are probably around the bottom or pretty close to the bottom and so I don't know that they will go up significantly in 2010 but I think they would be around where they are right about now, maybe a little bit higher. It is going to be a function of, commodity price and activity. So, I think we will be able to do things along the lines of what they're costing today.

Neal Dingmann - Wunderlich Securities

Okay. And then last question I'll just get back in the queue as far as obviously you’ve got a lot in your plate between off and onshore. What's your thoughts as far as you're looking into acquisitions, I mean obviously you are always opportunistic, but is there something pricing that would get you excited or is it more you have got enough on the plate?

Scott Josey

We very much like our organic opportunities set. Thousands of locations in the Permian, lots of things still to do on our shelf assets, and a very good prospect inventory that we have hardly tapped in the deep water. So, plenty to do with what we have already, but we are an opportunistic company. We would love to do a transaction if we thought it made sense. That was one of the reasons that we were so focused on the liquidity this year was that the ability to, one is make sure that we could preserve and maintain and exploit this franchise that we think we have created to be able to be prepared to take opportunities like the Anadarko opportunities that have come our way, most recently. And so we think we did the, we took the right steps this year. We have not seen many transactions that have gotten us excited here over the past year and hopefully there will be some that materialize. But we are always looking.

Neal Dingmann - Wunderlich Securities

Thanks, Scott.

Scott Josey

Thank you.

Operator

The next question comes from Michael Jacobs with Tudor, Pickering, Holt. You may proceed.

Michael Jacobs - Tudor, Pickering, Holt

Good morning, everyone.

Scott Josey

Good morning.

Michael Jacobs - Tudor, Pickering, Holt

Scott, quick personal comment, I know how seriously you take guidance so I can only imagine how frustrated you are with third party related issues, but nonetheless, I would like to dig a little bit deeper into the ’09 production guidance. If Vermilion 380 was roughly $20 million a day of guidance, it seems like there may have been a couple of other fields that were originally in that 2009 guidance that may also have been deferred. Can you talk about what other fields affect the '09 forecast? And what might roll into 2010 numbers?

Scott Josey

Sure. What I tried to focus on is really just what the main issue was and is the delay at Vermillion 380. As I mentioned, we had a series of pipeline delays and shut-ins in the third quarter. They were unexpected. They were, and even though in the each well or each shut-in is not that high, when you aggregate it, it begins to have an effect. We also had expectations that some of the outside operated projects would come on a little bit sooner. We thought Daniel Boone would be on a little bit sooner, we thought DKA 21 [ph] would be on a little bit sooner. I don't want this to be miscommunicated. We are not complaining, it is just that they came on little bit different days than what we thought originally and we are pleased with where they are today, but those delays do have some effect.

So, when you take something as significant as Vermilion 380 and then couple it with some small variations that in the aggregate add up, then you are right it does, it adds up to more than what we could -- more cushion than what we had in the rest of the year. We also, we had already talked about our SMI 150 project that we were experiencing some mechanical delays, but we have felt that even though, it probably wasn’t going to come on before the end of the year that we would be, that's why we said on the last call that we would be probably around the lower end of the range. These other things came as a more of a surprise to us. So you are right we do take this very seriously. We do our very level best to get this right.

And it’s frustrating when we can’t seem to get it quite right. It’s frustrating for us; I know it is frustrating for the market but it is the nature of the Gulf of Mexico. These aren’t resource plays where we are, it's a different kind of business, a different environment and as hard as we try it seems that, we are always going to have some kind of variation in it. We have had years when we have been within the range, we've had years there where we were going to be way above the range and get hit with a hurricane, and then we have this year where we have come in below, below the range. But it is not due to something that is wrong with the asset base. It is not something that's wrong with our properties or our wells; it is just due to deferrals that are difficult sometimes most of the time, but occasionally we don't.

Michael Jacobs - Tudor, Pickering, Holt

With the deferrals and with your current pace of spending, and especially the big ramp in the Permian and modest exploration success, can you give us a wide range of production expectations for 2010 in terms of growth?

Scott Josey

Well, I can't yet Mike. We'll be able hear shortly, but what I can say is that even with this shortfall for 2009, actually we are not losing production, it is just being deferred. It is going to come on at the end of the year, and should make 2010 just look a little bit better. But when you look at our CAGR for production growth since we became a public company, it is about 17%, which is unheard of for a Gulf of Mexico based company. Year after year, people have concerns about our ability to grow our asset base, and year after year we have been able to do that. So, we will be back with you shortly about that, and my expectation is that we would continue to be able to increase production.

Michael Jacobs - Tudor, Pickering, Holt

One question on the on shore, the Sprayberry target that you referenced where you mentioned 100 to 120,000 barrels per well, was that on 160 acre spacing and if so, what would you expect per well recoveries to be as you down space to 40s?

Scott Josey

In our Deadwood field, where we believe we're going to have 150,000 barrel equivalents, there's virtually no production out there. Then in the Scottish, we're not sure how far we'll be to take that property, but we are hoping that we can at least take it down to 80 acre spacing, and if that works, then you never know, you might be able to take it down even further. On the Scottish Rites field, this is an old field, and so even though it was on a 120 acre to 160 acre spacing before we took over, we don't think the recoveries are like you would get today with 120 are to 160 acre spacing. The frac jobs are better, the drilling techniques are better, and so we are still expecting 110,000 barrels per well to 120,000 barrels per well at Scottish Rites even if were to take it down to about 40-acre spacing.

Michael Jacobs - Tudor, Pickering, Holt

I think typically you have been doing shorter term kind of well by well commitments or five well commitments on your rigs. Are you looking at locking in rigs for longer periods of time?

Scott Josey

Yes, I think we will. Now that we are planning our ramping up activity significantly in the Permian, I suspect that we will be locking in rig contracts over longer periods, which we did. If you go back a couple of years ago, we would typically have 10 well to 15 well programs per rig.

Michael Jacobs - Tudor, Pickering, Holt

I will hop back in the queue.

Operator

Your next question comes from the line of Richard Tullis from Capital One Southcoast.

Richard Tullis - Capital One Southcoast

Scott, going back to the Permian real quick, I know you were talking a little earlier about significantly ramping up activity there. You're benchmarking off the current four rig pace rather early in the year when you were not doing too much activity there at all, is that correct?

Scott Josey

We started the year with I think one to two rigs, pretty quickly got down to one, and once we finished that up, we didn't do much of anything for a period of about four or five months. Then we began doing a little bit more drilling around our Deadwood field with one rig, and then have steadily, once the Board approves some additional capital spending, we targeted most of that for the Permian. So we have steadily gone from one to four, and I think by year end we may have as many as six. For 2010, it is hard for me to say, but I am not so sure it doesn't average around 10 or so rigs for 2010.

Richard Tullis - Capital One Southcoast

Daniel Boone, I know it is flowing around I guess around 7,000 barrels equivalent gross right now. Is that the max rate you see there?

Scott Josey

Well, Richard, we always try to let the operator handle those questions. I think it was all designed to handle as much as 10,000 barrels a day, and it is producing like you said around 7,000 barrels equivalents. That's my understanding, and I think it is doing very well, the pressures look good. But that's really W&Ts call on what rate they want to produce that property. We interact with them very closely, and vice versa. So, at the end of the day, it will really be up to them, but the well looks good and pressures are good so we think it is a real nice project for both companies.

Richard Tullis - Capital One Southcoast

What are Bass Lite and Northwest Nansen producing right now?

Scott Josey

Bass Lite, we have been very pleased with the performance of Bass Lite. That project continues to produce about 100 million a day of natural gas, and is very strong, and looks good and frankly is exceeding our expectations. So it is doing very well. Earlier this year, we did have compression installed on the platform of Williams, who is the takeaway pipeline on that property; did put in a compression, we tested it the other day. That was another reason we were a little bit short on production in the quarter because the well is producing at a little higher rate than the compression can handle, but that's fine. I mean this is a good thing Bass Lite is exceeding our expectations. So to the extent that it declines, the compression is sitting there ready to go to keep the rate up as high as possible. But we think our ultimate reserve recovery on Bass Lite is going to be much higher than what we originally designed that development. Northwest Nansen, it is producing about 25 million cubic feet a day and about 3,000 barrels of oil per day.

Richard Tullis - Capital One Southcoast

I know you had the unsuccessful wells, Corr Dodge and Sherwood earlier this year, but do you anticipate drilling any more deep shelf wells say into 2010? I know the strategy hasn't been proven out yet for the players there, but if it does work with the close proximity to shore and the lower development costs it seems like could be attractive.

Scott Josey

I think there's potentially a lot of promise in the deep shelf. We are not trying to build a business on the deep shelf any more than we are trying to build a business just in the Deepwater or just on the conventional Shelf or just in the Permian or just in the unconventional. We believe in balance and diversification. We've had a good success in the deep shelf and we've had some things that didn't work out quite as well as we thought. But it will be a part of our portfolio going forward. We are very pleased with for instance, the South Tim 49 discovery that we had in the deep shelf.

So, it will be a part of what we do. I don't see it as the major part of what we do in the Gulf, but it will play some role, and that would be on a prospect to prospect basis. Yes, we had some dry holes there. The deep shelf is still largely untested at this point. There really have not been that many deep shelf wells drilled. I know there are companies like McMoRan that are very much dedicated to it and they've had some good success and we are happen to see that, but we still have a long ways to go before this gets figured out completely. It will be part of what we do, and we expect to drill some more.

The reason I mentioned, Sherwood and Corr Dodge, these are good prospects. We liked them, McMoRan liked them and they were good shots, but our net exposure on those two wells was not very much and so for us to take some good shots and not have to expose that much capital, we think that's the kind of things we are suppose to do, although we wish they had been successful. As I mentioned I think it’s on the last call that even (inaudible) is not a complete bust. There is a shallower prospect that we will drill probably before the lease expires, I think it is a 15 to 20 Bcf type of prospect that will get drilled down the road, so pretty relatively low risk prospect.

Richard Tullis - Capital One Southcoast

Okay. And then just finally, Scott, I know you mentioned you have picked up a small amount of Bakken acreage recently. When you look across the unconventional space, what areas would you ideally like to be in?

Scott Josey

What we have mentioned to the team, which we are happy to have in house is that we are going to look at some of the existing areas, and to extent that we could find positions in some of the more proven areas, we will look at that but a lot of those positions, they are so costly to get in that we questions the economics and particularly those that are focused mainly on natural gas.

The areas that we would like to focus on are going be more oily in nature, so that's one of the reasons for interest in the Bakken. We have been looking at the Bakken for a while, I think it has some promise, so we are really just dipping our toe at this point, hopefully over time we will be able to build a little bit bigger position up there. I think the main focus for this group would be hopefully the oil shales, and we've looked at a lot of deals, and are starting to get close on some others, and I think by our next call we will be able to talk more about some of the other things that we are doing.

Richard Tullis - Capital One Southcoast

Thanks very much. I appreciate it.

Operator

Your next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

Most of my questions have been answered, but just a couple on Wide Berth you mentioned you were considering various development options. Can you talk to the potential range in production from the discovery in?

Scott Josey

We can go along with our partner or there is another nearby discovery that we could look at trying to do jointly, so we will just see where that goes. Also, some of it is a function of, which host platform that we pursue and there's at least two or three options to pursue there. After Gopher, I am a little bit reticent to give out rates because it seems like we are off just a hair, we get punished. Wide Berth ought to be somewhere in the range, in the vicinity anyway of around 40 million a day to 50 million a day and 2,000 barrels of condensate to 3,000-barrels of condensate per day, so that's ballpark.

Brian Singer - Goldman Sachs

If we look at production trajectory over the next few quarters, I think you mentioned 360 million cubic feet a day is where you are now, and should we assume that that includes the 7,000 BOE a day at Daniel Boone.

Scott Josey

Yes, it does. We've got a few other smaller projects that are coming online as evidence by the number that we provided the 128 to 30, for the year production total, the production is quarter-to-quarter, third, fourth quarter is probably about flat, so we had a decline in the third and that we've gradually been ramping that back up, and there were a few other things that were set to come on will see a steady increase, but most of the impact is going to be late in the fourth quarter, so we probably don't see a significant increase in production for the fourth quarter overall.

Brian Singer - Goldman Sachs

If we look at offshore then, the biggest contributor would be the Vermillion 380 coming back on and then SMI 150 and then is there a lull until Wide Berth coming and that's another big step up?

Scott Josey

We would have, like I said Vermilion 380 and SMI 150, there's a number of other recomplete, et, cetera that we can do, for instance, our High Island 116 well. We've talked about negatives, we haven't really talked much about positives, although I guess we did mention Bass Lite, but we've had other properties that have done a little better than we thought, and one of those on the shelf is High Island 116. It has produced a little more this year than we expected and it has done this to us before, where it goes on longer than we initially expect, so we have got some very good recompletion opportunities there, so we have got a lot of things still to go do next year. I think if you are looking for the big volumes that would come on. It's going to be Wide Berth and, Balboa know at this point.

Brian Singer - Goldman Sachs

Great, thank you.

Operator

The next question comes from the line of Phil Dodge [ph], Towey Brothers Investments [ph].

Phil Dodge - Towey Brothers Investments

Scott, on the Lucius prospect, can you tell us how much being close to the Hadrian de-risks that in your opinion?

Scott Josey

Phil, that's hard to say, but I will say that is certainly what intrigued us about the prospect. I know that's what intrigued Anadarko first, and we are happy that we are one of the first companies that they called when they were looking to sell down some interest, but I think there has been about three wells drilled to-date between Exxon, ENI Petrobras, and they look pretty significant. If this were just a ranked wild cat, it may not have been something that we would have pursued, but the fact that you've already had success close by does make us feel much, much better and much more willing to risk capital there, but it's still an exploratory well. Exploration, you got chance with for the success, but you also have a chance of it not working out, so but it's great prospect and we are happy to be in it, and it f it works it has a tremendous potential.

Phil Dodge - Towey Brothers Investments

Let me ask my other question on the Permian, I know we are a month or month-and-a-half early on the 2010 details, but let me ask the question this way. If that were not object, if you could spend a chosen amount attractively in the Permian basin next year, how much higher would that be than what you are spending in 2009?

Scott Josey

This year in the Permian, we started the year off looking at spinning only about $30 million. We have increased that as a result of our mid year meeting with our Board to where we will spent probably $50 million to $60 million. So we are ramping it up but I am hopeful that we are spending in the $100 million to $200 million range next year in the Permian. We just have numerous wells to drill out there, and very good opportunity set, and like I said, in a year in which we focused on liquidity, we starved some capital out there, and think it was the right call because costs went down and commodity prices have gone up and now we as a company feel much better about where we stand and so we are hoping to I guess get after it in the Permian in 2010, and beyond. We have got a great team out there; they have lot of opportunities and lots of things to go do.

Phil Dodge - Towey Brothers Investments

Of that can you divide it into how much would be spent for the developing debt within Scottish Rites and how much would be for additional targets?

Scott Josey

Well, with Deadwood we’re still going to proceed in a measured pace. But we very much like what we see currently I mean this is an area where there was nothing. It's really an exploration type of project in the Permian and out of the 11 wells that we have drilled we have been very, very happy with it. We continue though to take a look at how we are completing those wells. At some point we will probably look at coring some wells. We are reconfiguring the tweaking the frac, fracs on those wells.

So, there is still a few things more for us to do before we just get into kind of a full scale exploitation down spacing program. I think Deadwood will have a pretty significant percentage of that budget. We have the Blue Plate acreage I think to the north of there, that we have just started to tap and to the extent that it works out the way we are hoping. We have got a number of things to go do there as well. Plus, still lots of locations is just on our existing Wolfberry and Spraberry and other properties. I would Phil, a significant amount of it is infilling a lot of existing stuff and a pretty fair amount of it is going to be towards exploiting these new plays and then along the way we hope to keep generating some more opportunities out there as well.

Phil Dodge - Towey Brothers Investments

Okay. Sounds good. Thank you very much.

Scott Josey

All right, Phil. Thank you.

Operator

The next question comes from the line of Nicholas Pope with Dahlman Rose. Please proceed, sir.

Nicholas Pope - Dahlman Rose

Lucius well is, do you all know at this point if that's going to be oil or gas? Do you all know?

Scott Josey

Well, at the end of day you don't, we don't know, and I would really defer that to Anadarko. The Hadrian wells have been primarily gas is what we, is our understanding. So, that's all I know about it at this point.

Nicholas Pope - Dahlman Rose

You made some comments about Gopher and I know when I came online there was some competitive production issues with that lease and I was wondering if Gopher was kind of, you are expecting it to get it back towards where you are initial expectations were and like your reserve expectations. Has that worked out as you had all hoped or is that, is it still a little below where you were expecting?

Scott Josey

That's kind of a two part question. The in terms of working out like we hoped from a reserve standpoint, the answer is, it is going to exceed our original expectations. So, we are very happy about that. As we mentioned on the last call and I know I mentioned it a little bit here. We had stated that we thought that the initial rate for Gopher would be around $125 million a day. I guess I am digressing and going back into some of the stuff we covered on the last call. These deep water wells are not tested ahead of time. We have to do these estimates with a lot of science and we generally get pretty close. The reason the well came on a little bit less than we expected was because it came on about six weeks later than we expected and our competitors there were able to get their well online although not at a real high rate but the reservoir pressure was a little bit lower than what we had anticipated initially.

The net-net, the well is going to produce more net to Mariner than what we originally expected. It is at a little bit lower rate than what we expected because the pressure was a little bit lower. We can't make up the difference all this year, it is also a partial contributor to our a little bit reduction in our guidance but up until the Vermilion 380 and few other things we thought would be fine there but overall it's going to produce more than what expected. We are happy with the outcome of a Gopher, but we don't seek to mislead anyone. We try to give people our best estimates of what we think it is, these properties are going to do. We are generally accurate. If we say it's going to come on 125 and it comes on at 115, we are only off by 5%. We are not sure why we get, why that turns into such a big deal. The well is performing every bit producing very much likely expected and will exceed our reserve expectations which we are happy about.

Nicholas Pope - Dahlman Rose

All right. Sounds good. That's all I have. Thank you.

Scott Josey

Thanks.

Operator

The next question comes from the line of Kristal Choy with Raymond James. Please proceed.

Kristal Choy - Raymond James

I had just one really quick question on the Permian if we go back to that. I thought that costs were more in the 900,000 range during I think, what you are estimating for maybe the second half of the year and I think you gave a 1.1 or something close to 1.3 at Deadwood in opening comments.

Scott Josey

Right. The reason, why on that is it we are increasing the frac jobs on those wells. So that is the main reason why the costs have come up.

Kristal Choy - Raymond James

Perfect. Okay well I guess that was my follow up question is I was wondering exactly what you were doing with your completions out there and what improvements you have seen?

Scott Josey

Well, what we do is we, we drill the wells depending upon the number of formations we encountered will usually determine the number of frac stages. So if we find six to eight intervals then we're going to have six to eight stage fracs. These fracs can, they take a while to pump, and day to two days some types to get everything done and then in some of the wells we have come back and followed up with production logs. We want to make sure we get a good sense of where the fracs have gone and how high they have grown, and where the production is coming from so that we use that information on the next project and so we said at the beginning of the year, that Deadwood was going be a bit of a science project for us.

We are still a long ways from being just a pure development project. Like say we like what we have seen but with all of this information, we continually tweak the completion processes and it seems that each time we get better and better performance from these wells. So, right now it looks like we are going to keep trying to increase the frac sizes and which starts again that's why the costs have been up a little bit.

Kristal Choy - Raymond James

Thanks a lot.

Scott Josey

Okay. Thank you.

Operator

The next question comes from the line of Jeb Armstrong with Calyon Securities. Please proceed.

Jeb Armstrong - Calyon Securities

Just thinking about deep water rigs what's your view on entering into long term rig contracts going forward?

Scott Josey

We've had the Diamond Ocean America rig under contract for quite some time, and that's been a good relationship for us, and we have made a lot of money as a result of having that rig under contract, whether it was a gopher, or even this year of being able to move on to Wide Berth are just a couple of examples of, by having this rig under contract that we were able to create value for our shareholders. Those rates have moved up significantly over the past few years, and by design, we did not want to have a rig contract much past 2009. Ours expires at the end of January of 2010.

So we have got about two and a half months left on the contract. The reason we did not want the contract to go beyond that was because there were so many new builds that were scheduled to hit the market in late 2009, 2010 timeframe. So the timing of the end of our contract was by design. You throw this world financial crisis, this meltdown that's occurred here over the past 12 months or so, we have seen a number of companies carve back their budgets, even in the Deepwater, and when they do that, sometimes their partners fall out.

We believe that going into 2010 we will just see how this plays out, but we think it is going to be a good thing for Mariner that we do not have a rig under contract because there are so many companies that do have rigs under contract that they're going to have projects, prospects that they're going to want to drill, and there's probably some chance that they have partners that fall out, and we will have an opportunity to review many of those and potentially be able to step in. So, I don't see us signing up a long-term contract any time soon, but we will just see how the market plays out.

Jeb Armstrong - Calyon Securities

So you are not averse to the idea you just got right now?

Scott Josey

Well, we've done it when we thought it made sense. If you go back a few three to four years ago, we thought it made sense to start looking at longer term contracts because we saw the market tightening, and our team did a real good job of anticipating that and getting the rig under contract at generally below market rates. What I mean by that, we weren't given any kind of a deal, it is just that we renewed the contract at a time when it appeared to us that rates could potentially keep going up, and so if we get it under contract at one rate and then the next thing those rates had gone up. So, we would actually have a below market rig contract. So that was good, our guys did a great job with that.

Your preference as an operator would, not have to have a rig under contract. The way we used to do things, where you have a prospect and you go find a rig and your partners and you go get it drilled. For a while, that was fine but for the last few years you wouldn't have been able to get your prospects drilled if you didn't have access to a rig. So that's why we put it under contract. I think in the environment that we are going into, 2010, and maybe a little bit beyond, not having a rig under contract is probably fine. But if rates were to get to a certain point that we thought was attractive, then we might look at it. So, we will just continue to evaluate the market, and hopefully our guys do as good a job in the future on managing that as they have done in the past.

Operator

The next question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed.

Scott Hanold - RBC Capital Markets

A couple of quick questions. Can you remind me, in the Permian, what was your highest rig count you operated at the peak?

Scott Josey

We probably, at the peak had 6 rigs to 7 rigs running but Scott that was when we were heavily infield drilling the Spraberry Aldwell Unit and we can now that we are much more spread out we can handle more rigs. So, going back to that is when you get to someone asked us a question back then is why just 10 rigs or 12 rigs or 15 rigs get going out there and the reason why is that even though we have about 18,000 gross, about 12,000 net acres, you get too many things going on in a localized area you start creating inefficiencies, instead of the economies of scale that you are looking for, you've got only so many roads and you start having trucks going past each other, and it just gets inefficient. We can with our operating staff that we have now and some of the increases there that we expect. We will be able to handle 10 rigs pretty easily and maybe more.

Scott Hanold - RBC Capital Markets

And moving up to Bakken any color you can lend on the acreage you all picked up. You made a pretty good point that you are not going to sit there and pay a high price, and a lot of the Bakken sort of course that we know today is obviously pretty tied up and our prices. Are you guys in North Dakota or where are you situated with that stuff you picked up?

Scott Josey

We are sort of in I think a little bit in Northwest of the Montreal County area. We’ve just dipped our toe in the water and I was even reticent even mention it other than we were this is all public information and we have already been called by a reporter about it. So I just thought I would just mention it. We have less than 1,000 acres at this point and we look at it a couple of different ways. Why do we think that the Bakken does have a lot of potential and now that some things have been worked out up there with the oil differentials et cetera it's a place that we have an interest, I am not sure that we are going to be able assimilate a large position but we will see.

But the other piece of it is there's probably something’s that we can if we're going to have an unconventional resources activity, at the minimum we will learn some things by participating with other operators in that area, and that hopefully transfer to other thing that we are doing and we'll have enough acreage in some of the spots where we will be able to operate also. So, worse case we get some expertise as well as good economics.

Scott Hanold - RBC Capital Markets

Clearly I mean you can probably get your best acreage deals by doing stuff organically on the ground. But to get something that is meaningful to Mariner, I mean really it seems the best and most efficient way to do that is, is to do a JV or to basically buy something that has got a big position there. Can you give me your thoughts on how you think in terms of making something meaningful to Mariner?

Scott Josey

It is an area that we like and have liked for a while and have looked at trying to make some, to do some transactions up in that area. They just have not worked out to date but it doesn't mean that we won't be able to do something here in the future. It will be a focus area but I don't I can't predict yet what will happen.

Scott Hanold - RBC Capital Markets

Okay you’re a minimal to like buying companies, they are doing JVs just what makes the most sense to you all?

Scott Josey

All of the above, we will consider, if we thought the, as long as think the economics outcome is, it meets our thresholds.

Scott Hanold - RBC Capital Markets

Okay. Great. Thanks.

Scott Josey

Thank you

Operator

The final question will come from the line of Michael Jacobs with Tudor, Pickering, Holt. You may proceed, sir.

Michael Jacobs - Tudor, Pickering, Holt

Just following up on the last comment, how willing are you to use the balance sheet in the context of transforming the company?

Scott Josey

Well I'm, Mike I guess one of the reasons that we, that we try to make sure our financial house was in order was potentially be able to do something transformational. We’ll do it in a heart beat if we can find something. The main reason we did some of the things we did was, as we said when we were on the road with some of the offerings were that we were trying to make sure we protected this company against -- that we bullet proofed the balance sheet against things that are outside of our control.

We were happy with what we did earlier this year. We were happy with the insurance proceeds that have come in, the capital discipline that we think that we have maintained and so the end result now is that we have got an $800 million borrowing base that we think by year end is probably virtually undrawn. Even some chance that we might even have is cash. So, we could do something pretty sizable just with that, plus, the capital markets have improved, the debt markets are better than where they were when we did the offering that we did. So, we would love to do something transformational. We did something we felt that was transformational with Force [ph] that's been a great transaction for us and I think for them. We would love to do the same thing and we are always looking.

Michael Jacobs - Tudor, Pickering, Holt

Okay and then three very quick housekeeping items. What’s the current production at Gopher you may have said it but I may have missed it.

Scott Josey

Gopher is currently producing $90 million a day to $95 million a day plus 500 barrels of condensate to 1,000 barrels of condensate I believe.

Michael Jacobs - Tudor, Pickering, Holt

Great. The Heidelberg $100 million plus barrel target on that we've heard from the operator, is that just for the middle reservoir? Does the include the deeper target, too?

Scott Josey

Well, the well was drilled initially for the Middle Miocene and that was a $100 million barrel, estimate as I understanding from Anadarko, $100 million barrel plus. I think everyone is pretty pleased with what we’ve found thus far, and so this next well will delineate that. Then there is an additional deeper prospect in the lower Miocene that is probably on the same kind of range. There is a lot of potential between this next well that gets drilled.

Michael Jacobs - Tudor, Pickering, Holt

That's helpful. Last item, where should we think about the Permian exit rate at kind of the end of 2010 production?

Scott Josey

I don't have that today, Mike. But I'll have a better feel for that when we have our call in early December. It's going to take us a little while to get the activity ramped up to where we want it. We have disproportionately we have not spent as much in Permian as what I would like. So, we think we can do quite a bit of, we can increase the production out there pretty significantly versus where it is today. So, I will be able to speak to that here in about a month.

Michael Jacobs - Tudor, Pickering, Holt

Great. Thanks for letting me hop back on.

Scott Josey

You bet.

Operator

At this time there are no further questions. I will turn the call to Mr. Patrick Cassidy for closing remarks. Please go ahead, sir.

Patrick Cassidy

Thank you, Stephanie. As a final note, I would remind you that this conference call will be posted on the Company's Web site this afternoon and will be available for replay through December 31st, 2009. Thank you for participating in our call this morning.

Operator

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

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