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Cimarex Energy (NYSE:XEC)

Q2 2011 Earnings Call

August 04, 2011 1:00 pm ET

Executives

Paul Korus - Chief Financial Officer and Senior Vice President

Mark Burford -

Thomas Jorden - Executive Vice President of Exploration

Joseph Albi - Executive Vice President of Operations

Analysts

Eric Hagen - Lazard Capital Markets LLC

Gil Yang - BofA Merrill Lynch

Joseph Allman - JP Morgan Chase & Co

Operator

Good afternoon, my name Petura, and I will be your conference operator today. At this time, I would like to welcome everyone to the Cimarex Second Quarter Results Conference Call. [Operator Instructions] Thank you. Mr. Mark Burford, you may begin your conference.

Mark Burford

Thank you, Petura, and welcome, everyone, and thanks for joining us today on our second quarter conference call. On today's call here in Denver, we have Tom Jorden, EVP of Exploration; Joe Albi, EVP of Operations; Paul Korus, Senior Vice President and CFO; and Jim Shonsey, VP and Controller. Mick is out of the office this week, and unable to make the call. But we did issue our financial and operating results news release this morning, a copy of which can be found on our website. And we will be making forward-looking statements in this conference call. I’ll refer you to the end of the press release for our disclaimer regarding forward-looking statements.

As stated in our earnings release, we reported net income of $166.7 million or $1.94 per share for the quarter, which includes $0.16 per share in noncash mark-to-market gain on our hedges. This compares to second quarter 2010 earnings of $124.6 million or $1.46 per diluted share. Our oil and gas revenues in this quarter totaled $452.3 million, a 24% increase compared to $364.9 million last year. In the second quarter, cash flow from operations hit $343.4 million, 32% greater than last year's second quarter cash flow, $259.9 million.

Our higher earnings in revenues and cash flow largely reflect the 33% to 35% increase in our oil and NGL prices, and liquid this quarter did account for 45% of our equivalent volumes. So I hit a few – a couple of hitting notes, a couple of financial metrics there, but we'll go ahead and jump in to the meat of the call. And I'll turn over to Tom Jorden to cover our operations.

Thomas Jorden

Thanks, Mark. I'd like to take a few minutes to kind of walk through our drilling program area by area. We have a great balance of opportunities to our Mid-Continent, Permian and Gulf Coast. Currently, we have 27 operator rigs drilling. 14 of those are in the Permian Basin, 11 are in the Mid-Continent and 2 are on the onshore Gulf Coast.

In the first half of the year, we drilled and completed 148 gross or 80 net wells. And as Mark said, we invested $757 million in exploration and development. Of our total expenditures, 48% were invested in projects in the Mid-Continent, 46% in the Permian Basin and 6% in the Gulf Coast and other. We're looking at full-year capital to be $1.5 billion to $1.6 billion. And as we've said time and again and it bears repeating, that really isn't a budget. That's kind of a rough guide between now and the end of the year, and we make our investment-drilling decisions as we go along. So that second half capital will certainly be a function of our drilling results, cost of services and our opportunity set.

As we look at that full year, though, we're expecting roughly half to be spread between the greater Mid-Continent area, about $750 million; $750 million more than likely to be in the Permian Basin; and then the remainder would be Gulf Coast and other so very, very nice set of opportunities and a fairly balanced program.

Starting in the Permian Basin, we drilled and completed 71 gross or 56 net Permian wells during the first 6 months of 2011, completing 94% as producers. And at quarter end, we had 10 gross, 8 net wells, still waiting on completion. Our drilling was principally in the Delaware Basin of Texas and Southeast New Mexico, and mainly targeted Bone Spring, Paddock, Abo, and Wolfcamp formations. Permian exploration development capital year-to-date through the second quarter, as I said, totaled $345 million for 46% of our total capital year-to-date. And I will walk through area by area. One of the things that we've said in the past and will certainly be apparent here is that our Permian program is split between several different programs.

First is our Bone Spring program. Bone Spring formation is really multiple plays over a large area. In Central Eddy and Lea Counties, we have our second and third Bone Spring horizontal oil play. Those are sands that are more of a conventional target and that we map channels. They do have some aerial extent, but it's not what we classically think of as an area-wide resource play. You have to have a focused geological picture, and we're targeting these sand accumulations.

In Texas, we've got the third Bone Spring. That's a little more aerial extensive, that’s sands, and we continue to realize great results from all of our Bone Spring drilling. Recent notable horizontal Bone Spring wells we brought on production, and these are 30-day average numbers, in the second quarter, we brought on our Irwin 13 Federal 2H well where we had 100% working interest. That well had a 30-day average of 810 barrels of oil equivalent per day. Our KHC 33-24 2H well, a 96% working interest had a 30-day average of 750 barrels of oil per day, barrel oil equivalent. And then our Parkway State 17 Com 3H, where we had a 94% working interest, came on first 30 days at 710-barrel oil equivalent per day. So production from the New Mexico Bone Spring drilling over the last 2 years has gone from basically 0 in July 2009 when we kicked off the program to over 10,000 barrels per day gross, currently.

For all the wells we have drilled and completed in our New Mexico second and third Bone Spring play, the gross first 30-day IP has averaged 590 barrel of oil equivalent per day. And that's 400 barrels of oil per day and 190 barrel of oil equivalent per day. So it does make some gas and gas-associated liquids. Our gross actual EURs have remained consistently averaging 570,000 Mboe, thousand barrels of oil equivalent. And of that 570,000 Mboe, 400,000 barrels is actual oil and 170,000 Mboe of gas and gas-associated liquids. That's our type curve. We've talked about that quite a bit in the past. And that second and third Bone Spring, our type curve is that 570,000 Mboe typically comes on. Our type curve is about 600 barrel of oil equivalent per day for its first 30-day average. And those wells cost currently between $5 million and $5.5 million to drill and complete. So very nice type curve. We're achieving very nice results there. And as in so many of our plays, our type curve is grounded in our actual results.

We have a solid drilling inventory of 170 gross operated drilling locations in the New Mexico second and third Bone Spring and over 140 Texas third Bone Spring locations. So we would expect this to increase over time, especially with the first Bone Spring or Avalon potential over our acreage. And I just want to talk about that for a second. That potential we talk about is in New Mexico, and Eddy and Lea County is in the second and third Bone Spring. In and around our acreage, the Avalon, our first Bone Spring, is an emerging play. There are a number of operators aggressively drilling. We have tested a few wells, and we'll be talking about those in subsequent calls. But we see that as another significant objective that has potential through a large swath of our acreage.

I also want to say, before I move on to other plays, that the second and third Bone Spring play in Eddy and Lea County is our most active leasing area, really company-wide, on a dollar basis. In the first half of the year, we've been very successful in that play acquiring additional opportunity. We have committed or spent $52 million in the first half in that play and picking up additional leases. And that is for leases in hand that are committed about 16,000 net additional acres. And those are acres that are focused on ideas we really like. So this is a continuing opportunity set for us. We have multi years of inventory there, and that's been just a really, really nice play for us.

Well let's talk a minute about our emerging plays, in particular our emerging liquids-rich play. We're moving along with our evaluation of unconventional plays, liquid-rich plays in the Delaware Basin, targeting the Wolfcamp, the Avalon Shale and the Cisco/Canyon or Penn Shale. We have a large acreage position of 160,000 acres perspective for some or all of that perspective for the Wolfcamp, Avalon, Cisco/Canyon. This year, we drilled and completed 5 new horizontal Wolfcamp wells, which bringing our total Wolfcamp wells drilled and completed to 12 wells.

Our first 30-day production from all of these wells has averaged 6.3 million cubic feet equivalent per day, which comprised as 48% gas, 31% natural gas liquids and 21% oil. We're still really timing this play. We're still trying to evaluate what the play means to us currently and the future potential. We have a lot of wells that are still waiting on completion. We have a lot of areas of the play yet to be developed. As I'm sure Joe will talk about, we’ve built an infrastructure in Culberson County that will allow us to further our drilling and completion in that area. We had to build a gathering system, and that's just nearing completion now. And that will allow us to test a lot more area of that play.

A lot of the wells that we've drilled to date have been concentrated in Eddy County and our White City area where we have approximately 60,000 net acres, and we've had very, very nice results there. Wolfcamp, one thing we can say is, particularly, as I move on to talk about Cana, the Wolfcamp has a steeper decline than our Woodford in Cana. There, we talk about a 55% year-over-year decline. In the Wolfcamp, we're observing a 75% year-over-year decline. But still, the wells are very profitable, delivering nice results. We're very, very pleased with what we see thus far. But again, I want to underscore, we're in the early stage of that evaluation. We have lots of objectives that have not been tested yet, and we're still trying to evaluate what it means to us. Like all of these plays, that 160,000 acres will have sweet spots. There will be areas where one or more of those objectives are perspective, and the others will not be. So we're still evaluating, but we're very pleased to report we're very encouraged by what we've seen yet so far.

And overall, looking at the Permian, before we move on, we have 14 operator rigs running in the Permian, 8 of those are in the Bone Spring play of New Mexico, 1 is in the Paddock play of New Mexico, 2 are in Eddy County, evaluating the Wolfcamp and that White City block. And then we have 3 rigs in the West Texas Bone Spring play. So we're very active in the Permian Basin. We're seeing good results from our drilling program. We have a great position and some great plays. And as we've talked about in the past, we have some of the most outstanding generators in our company working the Permian Basin. They continue to find new opportunities. We've been very aggressive acquiring additional leasehold. For those of you that follow the state and federal sales in New Mexico, we have been one of the most aggressive participants in those sales. So in this environment, we're able to make a very, very good return.

At the moment, we worry, as we always worry. We have cost creep and competition. We're seeing our cost go up, and we're seeing a lot of new entrants still into the Permian Basin. So we're seeing good returns in our Permian basin oil plays. But as always, it's about returns and we are forging ahead, cautiously worried about some pressures to our returns.

Moving on to Mid-Continent for the first half 2011. In the Mid-Continent, we drilled and completed a total of 86 gross or 32 net wells and completed 100% of those as producers. At quarter end, 22 gross and 8 net wells were waiting completion. Our Mid-Continent exploration development capital through the second quarter totaled $363 million or 48% of our total capital. Of course, the majority of that current-year drilling activity has been in our Anadarko Basin, Cana play, our Woodford Shale play, where Cimarex drilled and completed 71 gross and 23 net wells. At quarter end, 22 gross and 8 net wells were being completed or are waiting on completion.

Since the Cana play began late 2007, Cimarex has participated in 257 gross, 100 net wells. Of total wells, 214 gross, or 79 net were on production at quarter end, and the remainder were either in the process of being drilled or awaiting completion. Our net second quarter 2011 production from the Cana play averaged 115 million cubic feet equivalent per day, which is a 53% increase versus the second quarter of 2010 average of 75 million cubic feet equivalent per day. Cana is a very, very active project at Cimarex, obviously, and it's also an active science project at Cimarex.

As much as we're forging ahead with hundreds of wells drilled, we still have a lot of questions that we have to answer. We're still investigating spacing. We're just now in the process of completing a pilot project. That's a 2-well pilot that we'll be able to talk about here shortly. We drilled 2 wells side-by-side and did a tremendous amount of science trying to map the fracture network and understand the actual drainage pattern. Within the core, however, and we define a core a lot of ways. But for the sake of argument, we'll define the core as that portion of the play that we think we can confidently say will be down-spaced, and we think the most likely down spacing within that core is going to be 80-acre spacing or 8 wells per section.

Within that core area, where we say the Woodford is 150 feet thicker, down to depths of 15,000 feet, we have 64,000 net acres. Now that's not the entire asset of ours, of course, but that's just the area we think fairly confidently we can say, we'll more than likely be down-spaced at 8 wells per section. Cimarex's asset within that area is 4 to 5 Tcf net of royalty. We have many years of future development. We're still expanding the play. In no way shape or form am I suggesting that we think our asset is confined to that core. In fact, we have 8 rigs currently working in the play, and 6 of those 8 are drilling outside that core, making very nice returns for us on areas that we'll be talking about on subsequent calls. We're still holding acreage drilling one well per section and increasing our understanding of that expanding core. Current AFEs are $7.5 million to $8.5 million at the core of the play, and Joe will give a little more detail there. So by whatever measure, Cana has been a very, very successful legacy asset of ours, and we'll be developing that for many, many years to come.

In the Mid-Continent, we have 11 operator rigs running, 8 in the Cana play, 2 are in the Granite Wash and 1 in the Texas Panhandle, 1 in western Oklahoma and 1 is working in southern Oklahoma.

And then finally, in the Gulf Coast, during the first 6 months of 2011, we drilled 3 gross or 2.3 net wells. One of which was successful. So we drilled a couple of dry holes. Actually, one of those dry holes was completed, but we stood out of the completion. Our Gulf Coast exploration development capital year-to-date through the second quarter totaled $39 million or 5% of our capital. We're drilling a well near the Jefferson County Airport, called the Jefferson Airport #5, and we're rigging up on the Pica 2 after recently finishing drilling the Amazon Queen #2 well. The Amazon Queen #2 is a smaller prospect, and we expect that to begin producing later this month. So the Gulf Coast is an ongoing part of our business. It's obviously gotten a lot of attention lately. It remains a high rate of return for us, a much, much smaller portion of our capital.

So overall, we like the balance of our program. We're achieving nice growth in our Permian and Mid-Continent. We see a rich and expanding opportunity set there. And Gulf Coast will continue to be that high rate of return program that will be a much, much smaller portion of our capital going forward. With that, I will turn the call over to Joe Albi, our Executive Vice President of Operations.

Joseph Albi

Thank you, Tom, and thank you, all of you for joining us on our call today. I'll briefly go over our second quarter production. I'll hit on our third quarter and full-year production guidance, update you on where we see current service costs and then finish up with a few comments about our recently announced sale of our Riley Ridge project.

Well, Q2 came in just about as planned, with reported average net daily equivalent production of 585.7 million per day. We came in just below the midpoint of our guidance of 580 million to 600 million, and down slightly from our Q1 '11 average of 590 million per day. Our second quarter numbers were impacted by numerous unanticipated pipeline maintenance and repair shut-ins in both the Permian and the Mid-Continent, which reduced our quarterly production by approximately 4 million to 5 million per day. And accounting for these volumes, we would have been just about a bit above the midpoint of our guidance and almost exactly flat with Q1.

We set a few new records in Q2. Our reported Mid-Continent net daily equivalent production of 284.7 million per day was a record for the region and represented 49% of our total company production. As Tom mentioned, a significant subset of this production comes from Cana, which averaged a record 115 million per day in Q2, and again, that's up 53% from the 75 million per day that we reported in Q2 '10.

Our reported Permian net daily equivalent production of 182.3 million per day was again a record for the region, and it represents now 31% of our total company production. Combined, the Mid-Continent and the Permian now make up 80% of our total production. Our combined Mid-Continent, Permian oil and NGL volumes also hit an all-time high of 33,704 barrels a day, which now represent 77.5% of our total liquids, which is again a combined high for the company. With a strong contribution from both the Mid-Continent and the Permian, liquids now make up 45% of our total company production, which is the peak liquid ratio for the company. These new records really continue to demonstrate our business strategy and emphasis on long-term growth in the Mid-Continent and Permian, with a focus on oil and liquids-rich gas.

As we discussed during our last call, we expected Q2 to be somewhat flat to Q1, anticipating that 40 million to 50 million per day drop in our Gulf Coast production from Q1 to Q2. When the dust settled, we saw lead drop in the Gulf Coast production. But as we've seen in quarters past, the drop was offset by continued production growth for our Mid-Continent and Permian programs. As compared to Q1 '11, our total Gulf Coast equivalent production dropped 32 million per day, from 149 million per day in Q1 to 117 million per day in Q2. That's a drop of 21.5%. Offsetting this, our Mid-Continent volumes increased 19 million per day, from 266 million per day in Q1 to 285 million per day in Q2, a 7% increase. And our Permian volumes increased 8 million per day, from 174 million per day in Q1 to 182 million per day in Q2, a 5% increase from Q1.

As compared to Q2 '10, our Q2 '11 total company equivalent production of 585.7 million per day was virtually flat or down 1% from our Q2 '10 average of 594 million per day. Breaking down the numbers, we see the same story, significant but anticipated drops in our Gulf Coast production, offset by attractive year-over-year production gains from our Mid-Continent and Permian programs. Over the last 12 months, our Gulf Coast volumes have dropped 73 million per day, from 190 million per day in Q2 '10 to 117 million per day in Q2 '11. That's a drop of 38%. Offsetting this, our Mid-Continent and Permian programs reflect a combined 64 million per day increase, with our Mid-Continent volumes up 37 million per day from 248 million per day in Q2 '10 to 285 million in Q2 '11, a 15% increase. And our Permian volumes make up 27 million per day, from 155 million per day in Q2 '10 to 182 million per day in Q2 '11. That's a 17% increase. Combined, the Mid-Continent and Permian programs, which now make up 80% of our production, grew at a respectful combined annual rate of 16%.

With our focus on oil and liquids-rich gas, we continue to see our product mix move more towards liquids. Our Q2 '11 reported net gas production of 325 million per day, and combined oil and NGL production of 43,500 barrels a day puts our current liquid ratio at 45%. That's up 38% in Q2 '10 and 44% in Q1 '11. Once again, the Permian and Mid-Continent are the real drivers to our liquids growth, with our Q2 ’11 Permian liquid volume now at 18,600 barrels a day. That's a 30% increase from where it was in Q2 '10; and our Mid-Continent liquid volumes now at 15,104 barrels a day. That's a 72% increase from where it was in Q2 '10.

I want to set the stage a bit with a few comments before touching on our remaining year guidance. First, during Q2, we added additional frac fleets to address our backlog of wells waiting on frac. We currently have 4 frac crews working the Permian and 3 working the Mid-Continent for a total of 7, versus the 3 that we had working in Q1 of this year. As a result, we ended Q2 with 16 net wells waiting on frac as compared to the 31 net wells we had at the end of Q1. Most of the accelerated activity occurred later in Q2, with associated production anticipated to show up here -- showing up and anticipated to further show up in late June and early July.

Secondly, we increased our operated rig count from 24 rigs in Q1 to 27 rigs at the end of Q2. And as Tom mentioned, we did this by adding 2 rigs to the Permian and 1 to the Gulf Coast, bringing our quarter end rig count to 14 in the Permian, 11 in the Mid-Continent and 2 in the Gulf Coast.

Third, as you are all aware, the success of our Gulf Coast programs can create significant periodic swings in our production, up or down. Our ability to accurately predict the timing and success of 50% to 60% COS high-rate Gulf Coast wells can and will have short-term impacts on our guidance. After our recent dry holes and experiencing mechanical problems on our Two Sisters #2 and Two Sisters #3 wells, which were on decline but adding 14 million per day in net production in June, we've reduced our current projection for 2011 Gulf Coast production from that of last quarter. The 30,000 foot view of our production should really be seen as having 2 different indistinct components. The first and most critical is our low to moderate risk programs; that’s the Mid-Continent and the Permian. These programs bring us predictable, long-life production and a deep, predictable multiyear inventory of drilling projects.

As we've seen quarter-to-quarter, these programs are the underlying catalysts to our long-term production growth. The second is our high rate of return and short R/P Gulf Coast program, which inherently brings a component of uncertainty in the timing of production adds and drops. Our production can jump up or come down significantly in short order. This program really needs to be seen for what it is. That's a high rate of return cash flow investment. In essence, we're investing $1 today and getting $2 back next month. With short-term production profiles, the individual Gulf Coast wells simply cannot add long-term production. But from a different, perhaps more realistic perspective, the success of our Gulf Coast program over the last few years really has had an indirect strong contribution to our long-term production, simply by spinning off high rate of returns and cash flow, which has been redirected back into our longer-term Mid-Continent and Permian programs.

We recently took a look at our production growth since 2007 and saw some interesting results, which really helped illustrate this point. In 2007, we reported average net daily equivalent production of 451 million per day. Using our Q2 '11 total company production of 586 million per day as a reference point, we're up 135 million per day from 2007. Over that same time period, our Mid-Continent production is up $93 million per day, from 192 million per day in '07 to 285 million in Q2 '11. And our Permian production is up 38 million per day, from 144 million per day in '07 to 182 million in Q2 '11. Combined, the Mid-Continent and the Permian programs make up 131 million per day of the 135 million per day increase we've seen since 2007, with just 4 million per day coming from our Gulf Coast program. What does it mean? It means that Mid-Continent and Permian have really been the underlying drivers to our long-term growth, while our Gulf Coast program, with large production increases in late '09 and throughout 2010 simply generated significant cash flow, which we use for reinvestment.

Well, looking now to guidance for the last half of the year, we've updated our model to reflect our increased rig activity, our accelerated completions and a reduction in anticipated 2011 Gulf Coast volumes as a result of our recent dry holes and mechanical problems. With our accelerated activity, we're projecting our Q3 volumes to be up from Q2, with a guidance projection of 585 million to 610 million per day. Our revised full-year guidance range is coming in at 595 million to 610 million, which is down 10 million per day on the low end and 25 million per day on the high end from our previous guidance of 605 million to 635 million that we gave in our last call. The majority of this reduction is simply associated with our revised forecast for the Gulf Coast.

Our projected midpoint for 2011 gives total company guidance of 603 million per day. It represents a slight increase to 2010, with our Mid-Continent and Permian programs projected to continue to offset any forecasted decline that we see in the Gulf Coast, which we currently have modeled at 43%, from a reported average of 174 million per day in 2010 for the Gulf Coast to a current full-year projection, which would include the production in Q1 and Q2, to give us a full-year average of approximately 100 million per day for the Gulf Coast in 2011.

Well, a few words on our lifting costs before touching on our drilling and completion cost. A look at our financial, it shows Q2 lifting cost coming in at $1.14 per Mcfe, with our year-to-date number falling in at $1.12 per Mcfe. That's right at the midpoint of our 2011 guidance of $1.02 to $1.22. Since mid-2010, we've seen an increase in expenses due to a number of factors: general cost escalations, our shift towards oil activity, numerous lease maintenance projects, but more impacted by increased saltwater disposal and power and fuel cost, which have been directly related to our pickup in new well activity. We are beginning to see early signs of stabilization in op cost, and as such, we're keeping our 2011 guidance projection steady at $1.02 to $1.22.

We continue to see increased cost pressure on our drilling and completion costs, as Tom mentioned, especially on the completion side. Since the beginning of the year, we've seen fracture stimulation costs go up anywhere from 5% to 100%, with the biggest increases coming from the Permian. Increased Permian industry activity has, by itself, significantly increased the demand for frac services. Equipment is available as we've demonstrated by securing additional fleets. But the service and material costs are what are rising, and they’ve risen somewhat sharply since the beginning of the year.

On the drilling side, we've seen cost increases in most all of our cost categories since the beginning of the year. But that said, we feel that the rate of cost increase may actually be slowing down, and we continue to stay focused on cost and design efficiencies where we can to help keep our cost escalations in check. As a result, we've seen anywhere from 0% to 10% increases in our core program AFE since last quarter. As an example, through operating efficiencies, we've kept our generic Cana AFEs, for the shallow and core areas of the play somewhat flat since the beginning of the year at levels of $7.5 million to $8.5 million. That's up – although flat for the last 6 months, we're still up about 10% to 15% from where we saw those costs in mid-2010.

Our recent New Mexico second Bone Spring horizontal AFEs have increased to levels of $5 million to $5.5 million. That's up from levels of $4.8 million to $5.2 million that we quoted in Q2, and this is due primarily to increased stimulation cost that are more directly associated with the change in completion design other than the change in service costs.

Our Paddock-Blinebry vertical AFEs have jumped a modest 5% to 10%, from $1.8 million to $1.9 million in Q2 to current levels of $2 million to $2.1 million here in the current month. And this is due primarily to overall cost increases.

As we continue to develop and refine our Woodford Shale play, we see our current AFEs running right now, $7.2 million to $7.7 million. This is up from the $6.5 million to $7.5 million range reported last call, and this is due primarily to increased costs associated with testing various completion designs. Once again, as we see this play, in particular, develop, we see it to have more of a chance to be like Cana, where various operating efficiencies will take root and we’ll see those costs stabilize and/or reduce.

Same neck of the woods, Tom had mentioned a little bit about Culberson County and our attempts to put in our own infrastructure, and really just a simple comment here. There's virtually little if any infrastructure out there, from gathering to power, to saltwater disposal, what have you. That's the bad news. The good news is, this provides us with an opportunity to control our own destiny, and we're simply putting ourselves in a position to build the infrastructure and maintain optionality for markets. And by doing this, we'll have access to at least 3 markets and hopefully more to help get our product moved.

Before turning the call over to Paul, I'd like to say a few words about the recently announced sale of our interest in the Riley Ridge project in southwest Wyoming to Denbury, a deal we closed on this past Monday. As you know, we've been developing this project over the last few years. And we had an anticipated plant startup date scheduled for fall of this year. Well, Denbury became our partner in the project last September after acquiring the interest of the majority non-operating working interest owner. And the sale of our 57.5% interest in the project simply made -- ultimately made sense from the standpoint of both companies. Where we saw a value in the project from the sale of methane and helium, Denbury saw value in methane, helium and CO2. This last Co2 source is an important part of Denbury's enhanced recovery strategy and was certainly a win for Denbury. A solid purchase price was certainly a win for Cimarex.

Selling a property outside of our core areas of activity for premium price and redirecting proceeds into our higher rate of return drilling program just simply made sense to us. Through the sale, we'll derive proceeds of $191 million, with $176 million paid at closing and another $15 million to be paid upon the successful startup of the plan. Net Cimarex hydrocarbon production of about 10 million per day was scheduled to occur in late fall, and that now is obviously and hasn't -- is not included in our guidance projections.

So in summary, Q2 was a very good quarter for us. Production from our long-term Mid-Continent and Permian programs continues to grow, setting new records for the company and exhibiting 15% to 17% annual growth. All the while, we're living within our cash flow and ended the quarter with money in the bank. Our shift towards liquids continues to hit the radar screen, with our Q2 '11 oil volumes now at a record level and the Mid-Continent and Permian liquids up a combined 46% from a year ago. These stats simply show our stripes, long-term growth in the Mid-Continent and Permian, with an emphasis on oil and liquids-rich gas. So with that, I'll turn the call over to Paul.

Paul Korus

Thank you, Joe. I'd like to recap a few things. While much has been made about our production being down 1% from a year ago and a 3% reduction in our guidance, I do want to point out that financially, things look much better. To remind everyone, Q2 this year versus second quarter of 2010, our revenues were up 24%, our cash flow was up 32% and our reported GAAP earnings were up 33%. We like those measures, and I think if we have successive quarters of those, we should be just fine.

Part of what drove the increase in revenues, cash flow and earnings, of course, was prices but also the shift in our mix. Like so many others in the industry, our mix is changing. A year ago, we were about 37.5% liquid, 62.5% gas. Now we're more like 45% liquids, 55% gas. So we are certainly benefiting by having that alteration in our mix and enjoying the benefit of the higher liquids and oil prices, both of which have remained remarkably strong. In addition, during the first half, we invested $750 million, but yet had no change in our debt outstanding or shares outstanding.

As we look to our revised capital program for the year, as we mentioned in the news release, from roughly what used to be a $1.4 billion expectation to now what is approximately $1.6 billion, the increase is almost all in the Mid-Continent. That stems from the non-core drilling that we are doing in Cana. So on the old numbers, our Mid-Continent expectation had been about $590 million. That is now about $750 million. So that's an increase of $160 million. Our Permian Basin activity is remaining pretty much as expected. But with cost pressures out there, we're seeing our estimate go from what had been $710 million to now something more like $750 million, a $40 million increase. In the Gulf Coast, although it was only about $40 million of our total $750 million in the first half is still expected to be about $100 million for the year, and there is no change to that.

We will have higher land and seismic investment this year between regular leasing, as well as some acquisitions of improved via purchase and sale agreements. We were about $64 million, $65 million through the first half of the year, probably on track to see that number be about $130 million, $135 million by year end. With the $1.6 billion of capital, question in terms of how will that be funded. We've pretty much, all through the year, expected our cash flow to be about $1.3 billion. We're certainly on track for that, given that the first half of the year was about $650 million. So, so far, so good, we're on track. So with $1.3 billion of cash flow, we came in to the year with $100 million -- over $100 million of cash on the balance sheet. We've worked our way through that. But with our property sales, of course, largely dominated by the sale of the Riley Ridge asset of what should approach $200 million in total. Those 3 things add up to the $1.6 billion. So we're in very good shape financially from that perspective, and laying a lot of groundwork for what we hope is much stronger growth in 2012.

With that, operator, I believe we are ready to entertain questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Bill Allman.

Joseph Allman - JP Morgan Chase & Co

It's Joe Allman, actually, with JPMorgan. I guess a couple of questions. One, for Tom, in terms of your plans for the Avalon Shale and the Cisco/Canyon, could you just talk about what you're planning on doing over there over the 6 months or so?

Thomas Jorden

Well, Joe, we have a few Avalon wells that we're drilling and testing. And we're -- the Avalon is a big area. So there's hundreds and hundreds of square miles out here where you say Avalon. But I will say in Lea County, New Mexico where it's oily, we are drilling a few wells between now and the end of the year, and we're testing some completion techniques. And if we get the kind of success that we think we will achieve and that the industry has achieved, I think there's a real good chance that, that will kick off an additional drilling program for us in the Avalon. And then we have in the Penn Shale, in Eddy County, we have completed a well, and we're just watching flowback on that. I don't really have anything to say on it because we don't have any conclusions yet, but we're just testing the producibility of the Penn Shale with modern stimulation, Joe. As I said in the past, we've drilled a number of Penn Shale wells in years past, horizontal wells in and around our White City area, but we've yet to put a modern shale stimulation on it. So we're just doing our first one and watching the results. So the Avalon's a big area, Joe, and I would anticipate that we will be out drilling the Avalon. In 2012, I would anticipate that we'll have an Avalon program that we'll be talking about. But certainly, your question is between now and the end of the year, we're testing a few things and we're going get our own learnings under our belt and continue to study the industry.

Joseph Allman - JP Morgan Chase & Co

Okay, that's helpful. And then looking at second quarter production, it appears that the Gulf Coast actually did not decline as much as you had modeled. I know it's very difficult to figure out where the Gulf Coast is going to go. And -- but so -- did the Permian production not rise as much? And with that -- and I think I heard you talk about pipeline interruptions. Could you just address that?

Joseph Albi

A couple of things there, Joe, on the -- first on the Gulf Coast production. I think the number we quoted was somewhere 100 million, 110 million or something like that in Q2, and it came in at 117 million. A couple of things happened there. Number one, right about the time of our call, one of our Jefferson Airplane wells #3 was down. And right about the time of our call, we were successful in restoring about 3 million per day worth of production from that well. So it came on and was not put into our guidance projection. Secondly, I think we'd mentioned that we are sidetracking our Jefferson Airplane #1 sidetrack well. That came on in about the middle of June and gave some second quarter contribution, and we kind of thought that might show up in Q3. We also had 2 wells, our Amazon Queen 1 and our Nine Dragons well that both, in essence, I'll call them, outperformed our forecast. So that said, that really is the reason for that. But when I look forward and I compare our plan for the Gulf Coast last call versus our plan this call, if I look at Q2 in our last plan, we outperformed it. But if I look at where our last plan called Q3 and Q4 to be, it was predicting right around 100 million per day. I don't know the exact numbers, but right around 100 million per day. Our current plan is predicting anywhere from 80 million to 90 million per day for Q3 and Q4. And really, that's a net result of the 2 dry holes that we had, where we had modeled some anticipated production from them. In particular, on the high side, those wells really affected our high side of our guidance. And then the Two Sisters 2 and Two Sisters 3 both decided, I guess talked to each other, and at the end of June, we lost one and then early in July, we lost the other. We're looking at remedial work to restore production there, and it doesn't look all that promising. One of them may present itself as a sidetrack candidate, where if we were to get back to it, it probably won't show up until later in this year and not give us much of a bang for our buck on production. So hopefully, that helps clear up a little bit on the Gulf Coast for where we see, and I really think that's important for you guys to understand how we're modeling that for obvious reasons, because that's the unpredictable one. In the Permian, there are a couple of things going on. One was the downtime I mentioned associated with plant shut-ins. That's probably close to 2.5 million per day worth of lost production, and we also had a handful wells that we shut in to -- in some of our frac projects to offset wells that we had shut in. So there's a little bit of influence there, but the biggest piece was trying to get a good, clear schedule on where we would have these fracs -- frac crews show up and when they'd show up. If you look at daily production, you're going to see that our Permian production really takes a nice bump at the tail end, about the mid to the tail end period of June. So it's really that accelerated activity in the Permian is not really starting to show its signs.

Joseph Allman - JP Morgan Chase & Co

Again, that’s helpful, Joe. And I think you said -- did you say that you're guiding for a 43% base decline in the Gulf Coast?

Joseph Albi

Yes. I think the number I quoted there was that we'd end the year with an average of about 100 million per day.

Joseph Allman - JP Morgan Chase & Co

Okay. So going forward, do you expect that the declines from the Gulf Coast will soften quarter-after-quarter? And just help us get comfortable with how to -- I know it's hard to forecast, but to better forecast Gulf Coast production.

Joseph Albi

Well, without mechanical problems and without additional drilling success, I would think you could presume that our 2012, maybe this will help you out, Joe, our 2012 production number might equate to -- with existing production, I'm just going to guess here and say, 45 million to 60 million per day. So that would be no new adds. And in general, I guess a safe number might be about a 50% production.

Thomas Jorden

Joe, this is Tom. We have 2 rigs running in the Gulf Coast. So it's very, very difficult to predict our exploration success. And obviously, we love what we're drilling or we wouldn't drill it. So I know it drives you crazy, but it's the nature of the beast. It's going to be hard to model, but as several people have said on this call, it's a real cash generator and helps us stay within that cash flow on funding these Permian and Mid-Continent programs. So we're going to continue to do it.

Joseph Allman - JP Morgan Chase & Co

It's helpful. Is it reasonable to assume no new production adds?

Thomas Jorden

If that were reasonable [indiscernible] run it. No, it's not unreasonable, but I can't help your model.

Operator

The next question comes from Gil Yang.

Gil Yang - BofA Merrill Lynch

Yes, this is a follow-on to that question. Can you -- I think you baked in sort of like a 65% success rate in your drilling program. Could you sort of update us on -- are you still using that success rate for the Gulf Coast?

Thomas Jorden

Well, Gil, this is Tom. There were 2 rigs that are currently running. I can say one probably is drilling a prospect that's very oily has a little higher success in that because it's offsetting a look alike. And then another prospect we're drilling currently has fair amount of risk here. So our actual historical success is 66% is the number we quote. I would say our go-forward program is probably going to be a little less than that if I had to just put a geologic chance success on it, probably 60%. And that's going to be a mix of projects that are a little higher and a little lower. But I think 60% is probably a reasonable go-forward number.

Joseph Albi

And the targets aren't as big.

Thomas Jorden

The targets aren't as big.

Gil Yang - BofA Merrill Lynch

Okay. You mean as the last couple of years?

Thomas Jorden

As the last couple of years. We do have some nice targets, but they are riskier. But a lot of what we're drilling right now are smaller kind of base hits. And then as we said in the past, we're always working on additional shoots to beef up the inventory of the business.

Gil Yang - BofA Merrill Lynch

With a couple of wells that were dry holed recently, have you learned anything that makes you more concerned that the risk is higher for the these wells and it was not...

Thomas Jorden

No. Overall, no. We've been doing this for a long, long time, and sometimes you're going to cross an area and a program where your geophysical anomalies are well-calibrated. And sometimes you're in an area where they're not very well-calibrated, and other things can fool you. And we know the difference.

Gil Yang - BofA Merrill Lynch

Okay. In the Permian, you highlighted the Bone Spring wells and you got -- the one you highlighted, at least, got better from what you drilled in the first quarter. Can you maybe give us a broader perspective of what the quality of the wells were that you've been drilling in the second quarter versus first quarter? And what -- and I think you said there was 140 or so wells in inventory there.

Thomas Jorden

Well that's -- yes, the -- inventory is a funny thing in this play because we're -- we picked up, as I said, we've committed or picked up 16,000 net acres here. So far this year, and we're still actively acquiring land. So we quote -- I think recorded 140 wells. That's not a static inventory. It's one of the most dynamic inventories we have in the company. And that every week, we wake up and it's being added to not only by additional acres, but by additional zones that we didn't fully model. We've drilled some very good wells. I think what I could say in terms of the quality of wells is that we would strongly reaffirm our type curve. And our type curve is 570,000 barrels of oil equivalent and 600 barrels of oil per day for our first 30-day average.

Gil Yang - BofA Merrill Lynch

Okay. But the wells you've been drilling are the wells you were talking this quarter, for example, the 3 that you pulled out. Are those sort of above type curve wells or are they sort of -- are they type curve wells?

Thomas Jorden

Those are -- the wells I quoted, all 3 were above type curve wells that we brought on in the second quarter. But that -- it's a program, Gil, and we're not revising our type curve upward.

Gil Yang - BofA Merrill Lynch

Well, so I guess the question I was getting to, if you're drilling, at least you're just certainly calling out the ones that are above type curve, as you get to those, say, 40 wells left in that inventory at some point of these 140, will those be necessarily below type curve?

Thomas Jorden

No, I think our inventory is in very nice perspective areas. In fact, a lot of the land we picked up -- I think a lot of the land we picked up has a fair prospect collection that may be above type curve. But we're not sandbagging. I mean, the type curve is the type curve, and we make it a capital decision. That is the economic parameters that we model. And we think that's what we're going to deliver, and the proof's in the pudding. I'd say that is our historical average. I would not take that 140 and downgrade it.

Operator

The next question comes from Eric Hagen.

Eric Hagen - Lazard Capital Markets LLC

Just a quick question on Cana. What are the prospects for possibly accelerating Cana in 2012 as you finish HBP your acreage and delineate it better? So more specifically, maybe to accelerate infill drilling in the core as you feel more confident that you can develop it on the 80s. And if there is an opportunity, what do you think is the potential for adding rigs there? I think you're drilling with 8 now. Could that increase by 4? Could it double? Just kind of realistically, what's a possible range?

Thomas Jorden

Well, Eric, this is Tom. We are looking at that now; just what the potential is for infill drilling. In the core, that's a complex problem, because there are a lot of different operators that are at work in there and one -- no operator can operate in a vacuum. So what's going to happen in that core is when it does go to down spacing, you'll see a lot of companies go to down spacing. We don't have particular calendar plans for that. I don't know if it will be within 2012 in the core. But -- in direct answer to your question, we're currently modeling that and doing some what ifs, and we don't really have anything to say other than we're looking at it.

Eric Hagen - Lazard Capital Markets LLC

How many years of drilling do you have left, Tom?

Thomas Jorden

Excuse me?

Eric Hagen - Lazard Capital Markets LLC

If you don't accelerate, how many years of drilling do you have left at the current pace?

Thomas Jorden

Oh we could -- I don't have that in front of me, Eric. I know if we just continue to drill one well per section at our current pace, that will carry us through well into the latter half of 2012. So we have the optionality to accelerate drilling. But I want to be clear to you, Eric, and to our listening audience, we watch those returns carefully. There are a lot of things that are -- it's not about production. I mean, production is important, but return on capital is ultimately more important to us. So it's a combination of optimum spacing. It's a combination of service costs. It's a combination of what we think are reasonable returns are, and all of those are in play. We're trying to optimize that program. We just, as I said, are in the process of getting data off the field of pilot project that will tell us a whole lot about downhole fracture geometry and what the ultimate spacing will be. I mean, we say that it's most likely 80 acres. There are some credible companies who are talking about spacing tighter than 80 acres. So we're trying to really dial that in before we get swept away with a big capital program that would be wasteful. We don't want that to happen.

Eric Hagen - Lazard Capital Markets LLC

Okay. And my follow-up was on the Gulf Coast. How many more wells do you plan to drill this year in the Gulf Coast? And based on -- and excluding Jefferson Airplane, which I think is really sort of an outlier, what do you think a typical successful well would add in terms of production volumes?

Thomas Jorden

There are a couple of questions there, and I'll let Joe chime in and help me here. But to answer your question of number of wells with 2 ridge running, we have 4 additional wells that we would expect to have completed and logged by the end of the year. And depending on our drilling time, that could be 3 or it might be 5. But right now, no drilling schedule. We're scheduled to have 4 additional opportunities tested by the end of the year. And these prospects are kind of all over the map. Some of them are higher potential, some of them are smaller. But the garden variety of Gulf Coast well, it's going to come on between 5 million and 10 million cubic feet a day and probably will be a 5 Bcf target ultimately. But it's very difficult in our program to talk about averages. Averages mean something in the Permian and Cana. They don’t mean a whole lot in the Gulf Coast.

Eric Hagen - Lazard Capital Markets LLC

No, I can understand that, Tom. And then heading into 2012, historically, have you always run a 1- to 2-rig program? I mean, do you think that -- is this rig more of a makeup rig? Or do you think you have enough targets to continue to drill with 2 rigs? Just kind of a -- maybe some insight into that.

Thomas Jorden

We haven't formed our 2012 plans yet. We're going to come together here starting in a couple of weeks and kick that off. I would say, right now, if we didn't have another 3D project to exploit, we would probably be looking at 1 rig in 2012 in our current inventory. But we're working on several additional 3D projects. Some of them are being acquired. Some of them are being reprocessed, and some of them are still being discussed. And this is our business. We do this all the time and if we can get additional 3D data in that had prospects and then we intend to do that, I think we'd look at recharging that inventory. But right now, I can't speak to that in any definitive term because we're still working on that.

Operator

There are no more questions from the phone line.

Mark Burford

Well, thank you, all, for joining us today on the call in this tough market. But we appreciate your attention, and we look forward to reporting some continued good results from Cimarex. Thank you very much.

Operator

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

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