Ultra Petroleum Q2 2010 Earnings Call Transcript

Jul.30.10 | About: Ultra Petroleum (UPLMQ)

Ultra Petroleum (UPL) Q2 2010 Earnings Call July 30, 2010 11:00 AM ET

Executives

Michael Watford - Chairman, Chief Executive Officer and President

Kelly Whitley - Investor Relations Manager

William Picquet - Vice President of Operations and Vice President of Operations for Rocky Mountains

Marshal Smith - Chief Financial Officer

Analysts

Brian Singer - Goldman Sachs Group Inc.

TJ Schultz - RBC Capital Markets

Ronald Mills - Johnson Rice & Company, L.L.C.

Subash Chandra - Jefferies & Company, Inc.

Raymond Deacon - Pritchard Capital Partners, LLC

Brian Corales - Howard Weil Incorporated

Noel Parks - Ladenburg Thalmann & Company

David Tameron - Wells Fargo Securities, LLC

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Joseph Allman - JP Morgan Chase & Co

Michael Bodino - Global Hunter Securities, LLC

Nicholas Pope - Dahlman Rose & Company, LLC

Operator

Good day, ladies and gentlemen, and welcome to the Quarter Two 2010 Ultra Petroleum Corp. Conference Call. My name is Jeff, and I'll be your operator for today. [Operator Instructions] I would now like to turn the conference over to your host for today, Ms. Kelly Whitley, Manager of Investor Relations. Please proceed.

Kelly Whitley

Thank you, Jeff. Good morning, ladies and gentlemen. Welcome to Ultra Petroleum's Second Quarter 2010 Earnings Conference Call. On the call with me this morning to discuss our second quarter results and our continued strategy of profitable growth are Mike Watford, Chairman, President and Chief Executive Officer; Mark Smith, Chief Financial Officer; and Bill Picquet, Vice President, Operations.

Before turning the call over to Mike, I'd like to cover a few administrative items. First, earlier this morning, we filed our 10-Q with the SEC. It is available on our website, or you can access it using the SEC's EDGAR system.

In addition, this call will contain forward-looking statements that involve risks factors and uncertainties detailed in our SEC filings. Please refer to our 10-Q regarding the selected financial information provided in this call.

Also, this call may contain certain non-GAAP financial measures. Reconciliation and calculation schedules for the non-GAAP financial measures can be found on our website also.

Second, Ultra will be participating in several conferences over the next few weeks. We will be at the Tudor, Pickering, Holt Energy Conference in Houston on August 11, EnerCom in Denver on August 24, Raymond James North American Equities Conference in London on September 15 and Barclays Energy Conference in New York, also on September 15. Please visit our website to review updated presentations and webcast.

Now let me turn the call over to Mike.

Michael Watford

Thank you, Kelly, and welcome back. Good morning. Joining me today on our conference call is Mark Smith, who will update us on the financial affairs; and Bill Picquet, who will take care of the operating issues for us.

Ultra Petroleum continued its consistency of profitability and growth through the first half of 2010. We established new production records for both the six-month period and the second quarter of 2010. Cash flow and adjusted earnings for both periods increased when compared to year-ago values. And most importantly, we delivered exceptional returns with a year-to-date return on equity of 44% and 19% return on capital.

We continue to execute on the profitable growth strategy and by that, we mean, we make money first and we grow second. We maintained our low cost and enjoyed increasing unhedged natural gas prices. We continue to gain operationally in Wyoming with the results of lower well costs. In Pennsylvania, we are gaining traction with early time production volumes on target and clear visibility on the second half production ramp up.

Now let me ask Mark to share the financial comments.

Marshal Smith

Thank you, Mike, and good morning. As you've seen from our press release, we had another very good quarter operationally with record production, continuing improvement in drilling efficiencies and reduced costs. Ultra's realized corporate natural gas price before the effective hedges was up significantly year-over-year as well as sequentially.

As we've previously discussed, a very positive impacts of REX-East and a 1.8 Bcf per day of increased takeaway capacity out of the Rockies. The quarter Opal first-of-month price has averaged 89% of Henry Hub. Further, Ultra's corporate realized gas price before hedges for the quarter was equal to the average Henry Hub price for the period.

From a financial perspective, we continue to be very well positioned. As of June 30, we had $8.3 million of cash and cash equivalents on hand and just under $1.2 billion in outstanding senior debt. Our total debt capacity is in excess of $2.5 billion, providing us with over $1.3 billion in unused senior debt capacity. I believe, most importantly, we again demonstrated strong organic growth, while generating industry-leading returns.

For the second quarter, our Wyoming production was up 18% on a comparable year-over-year basis to a record 52.4 Bcfe. Once again, our quarterly production was an all-time high for the company. You'll hear more about this from Bill in a minute.

Natural gas prices, excluding the effect of hedging for the second quarter, were $4.09 per Mcfe, an increase of 51% over prior-year level. This was due primarily to the completion of the REX-East Pipeline segment last year. Condensate prices registered $67.64 per barrel for the quarter, largely as a result of our increased production levels. Revenues for the quarter, including effects of our hedges, measured $266 million.

Corporate lease operating expenses for the quarter increased year-over-year to $0.89 per Mcfe as a result of higher severance and production taxes due to higher commodity prices. This was partially offset by reductions in our unit operating costs and gathering expenses.

Looking at our cash costs in Wyoming, excluding severance taxes or our field level costs, it decreased 6% year-over-year on a unit basis to $0.46 per Mcfe. Our transportation costs, which represent our charges in association with [ph] REX amounted to $16.5 million this quarter or $0.32 per Mcfe on our total production volumes. Our DD&A rate for the quarter registered $1.08 per Mcfe. General and administrative expenses decreased on a unit basis year-over-year to $0.12 per Mcfe, while interest costs were flat at $0.22 per Mcfe.

Net effect of all these factors was an 8% increase in all-in cost of $2.62 per Mcfe compared to $2.43 in the second quarter of 2009. I'd like to point out that our all-in cost numbers include all costs, including gathering and transportation, unlike some of our peers. Again, this increase in all-in costs was largely driven by higher severance and production taxes due to higher commodity prices and was offset in part by our continued reductions in fuel cost and G&A.

As a result of the increased production improvement, realized gas price before hedges that I mentioned earlier, as well as our continued focus on operational improvements in cost reductions, our operating cash flow increased over the comparable 2009 quarter to $178.2 million. This provided for an operating cash flow margin of 67% and $1.16 in cash flow per diluted share. On a unit of production basis, our cash flow for the first half of the year amounted to $3.40 per Mcfe when compared to our all-in F&D costs for 2009 of $1.29 per Mcfe, provides us with a recycle ratio of 2.82x.

Adjusted for unrealized gains associated with the mark-to-market position of our hedges and nonrecurring litigation expense, our net income registered $82.8 million for the quarter for a 31% adjusted net income margin and $0.54 adjusted earnings per diluted share. In terms of break-even levels, our net income breakeven is now $2.49 per Mcfe with cash flow breakeven at $1.19 per Mcfe. Our adjusted return on equity on an annualized basis for the second quarter was 42%, and our adjusted return on average capital employed was 18%.

Cash provided by operating activities during the quarter amounted to $203.5 million, with cash used in investing activities totaling $337.4 million. These investment activities were largely comprised of $341.2 million in oil and gas-related capital expenditures to $17.8 million in gathering and infrastructure expenditures. Over the quarter, net cash provided by financing activities totaled $136.2 million consisting primarily of $135 million in net borrowings on our senior bank facility.

I want to spend a minute on our price outlook for the balance of 2010. Opal prices continue to be up meaningfully. Last year, August through December first-of-month index prices at Opal averaged $3.46. This year, balance of 2010 pricing is currently trading at around $4.10, which reflects an increase of over 18% above prior-year levels. This change is very important to us.

I previously commented on the fact that when one focuses on our firm transportation on REX, combined with our growing production in Pennsylvania, one would see our forward corporate basis improving to approximately 94% to 96% of Henry Hub. In fact, for the second quarter, our realized gas price before hedging registered $4.09. This was equal to the average Henry Hub price for the period.

For our unhedged corporate gas price for the second quarter, in fact, registered 100% of Henry Hub. Again this change in corporate discounts driven by: first, the effects of REX on regional takeaway capacity and as a result, Rockies prices; second, our increasing production in the Northeast; and third, our firm transportation capacity on REX.

Moving to hedging, as detailed on Page 5 of our press release, we currently have approximately 44% of our 2010 forecast natural gas production hedged through a fixed price swaps at a weighted-average price of roughly $5.49 per Mcf. As of today, for calendar 2011, we have about 133 Bcf hedged or approximately 50% of our 2011 forecast production at a price of roughly $5.83 per Mcf.

I wrap up my comments by pointing out that on Page 7 of our press release, we continue to confirm our full year 2010 production guidance at 215 Bcfe and our establishing production guidance for the third quarter at 55 Bcfe. We provide additional detail on our outlook and guidance on our press release.

I'll pass it off to Bill for an update on our operations. Bill?

William Picquet

Thanks, Mark. In Wyoming, in the second quarter, Ultra brought on stream 68 gross, 37 net new producing wells, average initial 24-hour sales rate for these new Pinedale producers was 8.5 million cubic feet per day. Ultra's operated Pinedale wells averaged 9.8 million cubic feet per day, while the non-operated wells averaged 5.7 million cubic feet per day. The highlight for the quarter was from the Ultra-operated Mesa, 7A1-28D, which flowed at 17.8 million cubic feet per day.

At the end of the second quarter, there were seven Ultra-operated rigs drilling in Pinedale and five non-operated rigs also working on Ultra interest lands for a total of 12 active rigs in Wyoming.

New Ultra-operated wells, with initial production during the second quarter, averaged 6.2 Bcfe EUR [estimated ultimate recovery]. We're continuing to drill in the best areas of the field and that will be the case for quite some time under the development rule set forth in the SEIS Record of Decision.

We're ramping up our five-acre drilling activity. We're currently drilling five-acre wells on several pads where we have pilot-spacing approvals. At the end of the second quarter, we've drilled 21 new five-acre wells year-to-date and expect to drill a total of 55-acre wells in our operated program for the full year. Our results to date are meeting or exceeding are pre-drill reserve expectations. We plan to expand the five-acre program as we continue developing these areas of the field.

The land [ph] resource is extensive. We believe it will ultimately reach a total of 15 Bcfe. A third-party reserve estimate at year-end 2009 places our remaining Wyoming drill location inventory at 5,584 gross, 3,101 net wells. During 2010, we anticipate drilling a total of 235 gross, 120 net new wells in Wyoming compared to 222 gross, 114 net wells drilled in 2009. We expect to complete a total of 250 gross, 140 net wells in 2010 compared to 228 gross, 107 net wells completed during 2009.

Operating efficiency in Pinedale continues to improve. In the second quarter, we averaged 14.5 days spud to TD for Ultra-operated wells, a new record for Ultra and the first quarter that we've averaged less than 15 days per well, a 30% improvement over the average for Q2 2009. During the second quarter, our average rig released to rig release was 17.5 days, down over 28% from our Q2 2009 average. 86% of our wells were drilled in less than 15 days from spud to TD. Our average operated well cost for the second quarter 2010 was $4.6 million per well.

Our completion operations results in Pinedale have also been outstanding. For second quarter 2010, we completed 48 wells in our operated program as we began ramping up our operating frac activity pace. We're averaging 26 stages per well in the first half of 2010 versus 25 stages per well for the full year in 2009. The average is just under $68,000 per stage during the first half of 2010 compared to $74,000 per stage for the full year in 2009.

The increasing average at frac stages per well during 2010 is attributable to the fact that we're drilling and completing in wells in the best areas of the field where there is more net sand pay per well. During the remainder of 2010, we expect continued improvements in our completion efficiencies. Overall in Wyoming, we're continuing to set new standards for operating efficiencies in our drilling and completions operations.

Shifting to Pennsylvania activities. Over the first half of 2010, we are continuing an active drilling program with a total of seven horizontal rigs working in the Marcellus at the end of Q2. Second quarter, we participated in a total of 37 new horizontal wells for a total of 64 gross, 38 net wells drilled and cased at midyear 2010. We're forecasting a total of 135 gross, 78 net horizontal wells drilled and cased during 2010. To date, our average lateral link is 4,400 feet or averaging 12 stages per completion. Our overall average well cost is $4 million.

During the second quarter, we initiated production of 20 gross, 13 net new horizontal wells, bringing our total to 21 gross, 14 net new horizontal producers in the Marcellus in 2010. By year end, we're overestimating that we'll have initial production from a total of 95 gross, 57 net new horizontal wells during the full year 2010.

We're cautiously forecasting the year-end total for new producers in anticipation of the upcoming transition from East Resources to Shell. As a result, we reduced our estimate on new produces at year end without reducing either the drill count or CapEx and without impacting our production estimates. We remain confident that we will meet or exceed our production forecast for the year as a result of well performance year-to-date, the accelerated pace of new producers to be added in the second half of the year.

In Pennsylvania, we averaged 33 million cubic feet per day net production in Q2, up from 20 million cubic feet per day in Q1. Our production volumes year-to-date and forecast for the remainder of the year on target to meet our estimated total of 20 Bcfe in Pennsylvania for the full year 2010. We anticipate averaging over 60 million cubic feet per day during Q3 and over 90 million cubic feet per day in Q4. At this point, we're accomplishing this performance with fewer wells contributing to the production volumes than we originally anticipated in our forecast. This is due to individual well rates exceeding the forecast.

Well declines have been flatter than we originally projected in our 3.75 Bcf EUR-type curve, and this positive well performance indicator will be watched closely as we continue to add producers at a faster pace during Q3 and Q4. We will quickly begin to gain more data and production history as our pace of new wells going on production accelerates over the second half of the year.

If the trend continues, we will likely push our EUR estimates upward. Consistent with our history, we're being cautious and waiting for more data before we draw any final conclusions about increasing EUR estimates. We're focused on indicators that we believe are significant. For example, the producing rate for our wells on their 60th-producing day is currently averaging 3 million cubic feet per day. This is a factor that speaks to the flatter decline rates. The accelerating pace of adding new producers, coupled with well performance that is currently exceeding our expectations, provides a clear line of sight to achieving our 2010 production goals for Pennsylvania. We're optimistic about the potential for future EUR upside.

Our results in the newly acquired acreage in Clinton and Centre counties where we're partnering with Anadarko are confirming our view that the resource will be more prolific in this area. We have previously stated that we expect EURs in this area to average about 5 Bcfe per well. So far, we have initial flow test on four wells averaging in excess of 7 million cubic feet per day.

This is very encouraging in view of the fact that all the rates were restricted by equipment limitations. These wells were choked back, flowing at very high flow and tubing pressures due to equipment capacity issues. Phase of adding new producers is heavily weighted for the fourth quarter in this area and will begin accelerating in the second half of the third quarter.

During the first half of 2010, we added to our acreage position in North-Central Pennsylvania. Our overall lad portfolio is concentrated in the five-county area in the north-central part of the state. At the end of Q2, we're now on 470,000 gross, 255,000 net acreage. During Q2, we continue to consolidate our leasehold, focusing on additions contiguous with our prior positions.

Good access to pipeline infrastructure and ability to perform billing units for extended lateral links and access to water supply for completions. We acquired the significant land position in Centre and Clinton counties in Q1, stated that one of the key attributes of this opportunity was the contiguous nature of the acreage. In the future, ability to add significantly to the existing acreage. In Q2, we've already began to make significant additions of complementary adjacent lands.

We also continued to add acreage across our holdings. We're strategically acquiring land that either fills out drilling units or is contiguous to our existing portfolio. They're assessing and optimizing our frac design and working to establish the optimum well spacing. We continue to gather data in our acreage position to answer these questions.

Earlier, we described our first microseismic program in our Marshlands acreage in Q1. In the second quarter, we obtained results for the second program in our East Resources AMI, though we conducted a microseismic evaluation on a horizontal well pair. During Q3, we plan another third microseismic survey, which will be conducted on our 100% Marshlands acreage. This evaluation will be conducted on a well pad with four laterals and will test wells drilled at 50-acre spacing.

We're plan to gather sufficient data early in the play to establish optimum spacing, so that we can effectively plan our development with appropriate pad placements. Our prior results suggests its spacing closer than our current 100-acre spacing, may be required to provide more optimal drainage of the resource. Assuming 80-acre spacing, we estimate that we have more than 5,100 gross, 2,300 net remaining well locations across Ultra's 255,000 net acre position. If we apply, we expect the EUR for these locations, the risk resource potential is over 8 Tcfe nets at Ultra in the Marcellus.

Overall, we're executing very efficiently in our development efforts. We continue to improve results in Pinedale drilling and completion efficiencies, and we're using our Pinedale experience to benefit our Pennsylvania performance in the early stages of Marcellus development. For example, in Pinedale, for years, we've recycled water to supply all of our frac water requirements.

In Pennsylvania, we're quickly applying this experience gained over years in Pinedale to recycle and reuse any flowback or produced water in our ongoing Marcellus frac operations. We're doing this very efficiently, and we've positioned our Marcellus infrastructure to provide benefits from these knowledge gained in Pinedale going forward. We'll continue to leverage our large project experience from Pinedale in other aspects of our Marcellus development.

With that, back to Mike.

Michael Watford

Think, Bill. We may have asked you to speak too much today.

We've enjoyed a very positive first half for 2010 at Ultra Petroleum. Our product prices are up and our costs are not because our margins remain strong. For the stronger production growth, our earnings and cash flow increased significantly. Our first-half 2010 recycle ratio is almost 3:1, a very good number. We have a healthy balance sheet and more available debt capacity than we have outstanding debt.

Our production growth rate accelerates in the second half of 2010, as the Marcellus program investments began to bear fruit. We're delighted with the growing scale of the Marcellus assets. We've been able to develop at an attractive cost that will lead to excellent margins and profitability.

Let me talk about our assets for a minute. I'm sure most of you are familiar with our core legacy Pinedale tight plant sand natural gas asset in Wyoming where our third-party reserve engineering firm sees 12 trillion cubic feet of undeveloped natural gas reserves. These reserves, as Bill mentioned, are located in 5,600 gross wells or 3,100 net wells. At a $5 million per well drilling and completion costs, that's a future development expense of $15.5 billion. This calculates to $1.29 per Mcfe finding and development costs.

In Pennsylvania, we're developing a second core asset in the Marcellus shale but we see 8 trillion cubic feet of natural gas reserves contained in 5,100 gross wells or 2,300 net wells. On an average $4 million per well, that equates to a future development expense of $9.2 billion or finding and development cost of $1.15 per Mcf. Buying the two assets totals 23 trillion cubic feet or future development capital of $24.7 billion or finding and development cost of $1.24 an M [per Mcfe].

If in an effort to be conservative, we want to add another $1 billion of cost, then the finding and development cost is still less than $1.30 an M [per Mcfe]. When you combine this long-term finding and development cost with our historical low operating expenses, we easily see why Ultra Petroleum is well positioned to continue creating value and generating profits relative to the future even in a $5 per Mcf natural gas pricing environment.

Lastly, I want to draw your attention to a three-year plan slide on our home page, which has been updated for changing lower natural gas prices, and it reaffirms our planned 20%-per-year production growth target. We achieve this with CapEx and EBITDA being essentially equal over the three-year period.

Now I'd like to ask the operator to open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

I think you indicated in your opening comments, Bill, that you were further emboldened by some of the well results you were seeing in Clinton and Centre counties. And I was wondering if you can add some more color on the EURs and IPs that you are seeing in those counties relative to the tim [ph] in the Northeast, as well as any additional -- any differences in cost, size, mix, et cetera.

William Picquet

Brian, this is Bill. As far as the initial results on the wells in Clinton and Centre county, we said that they averaged over 7 million cubic feet a day on initial tests. Due to the equipment limitations, we were unable to produce them at higher rates but they were producing at quite high of flow and tubing pressures, some in excess of 4,000 pounds at those rates. And we don't have enough production history at this point in time to comment on the EURs, but we suspect that those initials rates or restricted rates that high 5 Bcf EUR estimate on the front end of that play is going to be something that may prove to be conservative, if we get those kind of results across the play. As far as comparisons are concerned, it's pretty early in the play to compare costs because the initial cost performance, as you would expect for any operator, is going to be higher on initial wells as they gather initial data, and we don't have final full cost for those operations at this point in time. As we said earlier, our cost or what we call the legacy portion of the land portfolio is averaging about $4 million and in our EURs we're still saying $3.75. Well, we have reason to believe that those are very conservative.

Brian Singer - Goldman Sachs Group Inc.

And are you seeing any differences in faulting that leads to any kind of greater well costs relative to the Northeast carrying any differences in geology affecting the cost structure?

William Picquet

The Marcellus is deeper and higher pressured than Centre and Clinton counties, and so the wells will be more expensive there. And we're still pushing our laterals further out, which is, ultimately, if everything else is equal, will result in more costs potentially, but we're also improving our drill performance. As you saw in Pinedale, and as I expect to see in Pennsylvania, we'll get better over the course of time. And so I can only tell you what our well costs are today. I think that, go forward, we'll see improvements in efficiency and we'll just see where cost of services go.

Brian Singer - Goldman Sachs Group Inc.

And lastly, you've acquired acreage in the Marcellus -- been acquiring acreage in the last couple of quarters. Mike, where do you ultimately see your Marcellus acreage position going? And how should we think about additional capital or capital within your existing plans that you would want to devote to additional acreage acquisition?

Michael Watford

Brian, I think when we started beginning of the year, we have a target of 250,000 acres by year end. We've already eclipsed that. Part of the attractiveness of the acquired acreage operated by Anadarko was the ability -- it was largely contiguous and 92% held by production, lots of access to water and pipelines, and there was available acreage adjacent to it. We thought we could drill more scale size there, and sure enough, that's happened. We don't have any targeted acreage number right now. We have some ongoing lease acquisition efforts in our core areas to fill in our drilling units. And when something strategic comes along that's contiguous in our backyard, we'll be glad to seriously evaluate it and put it from the table, but there's no long-term goal right now in terms of acreage numbers.

Operator

Our next question comes from the line of Joe Allman with JPMorgan.

Joseph Allman - JP Morgan Chase & Co

In the Pinedale Anticline, you mentioned that your results so far with 5-acre spacing meet or exceed your expectations. Could you talk about what you're pre-drill expectations were there?

William Picquet

Just tell you about what our wells are averaging, they're just slightly less than 5 Bcfe per well in the area that we're drilling right now.

Joseph Allman - JP Morgan Chase & Co

Where are you drilling those 5-acre space well so far?

William Picquet

They are all located up in the kind of north-central area of the field this year, where we're drilling north in the river, in the Mesa and Riverside areas. Some of the best in the field.

Operator

Our next question comes from the line of Mike Scialla with Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Wanted to ask about the new venture program you're setting up, what the focus might be there? Is it going to primarily trying to establish grassroots kind of to hold a new place and primarily on the Rockies? Any preference, oil versus gas, anything you can add on that?

Michael Watford

Sure, Mike, the preference is profits, preference is margins. We care not or I care not whether it's oil or natural gas, and we care not really where it's located, although our focus is U.S., not international. And we decided it was time given our expenditure budgets are up to $1 billion. We have EBITDA and cash flow here in the next couple of years being well above $1 billion. We're trying to make some plans for the post-2012 time period. See if we can, we have two legs to our stool now, the Pinedale opportunity and the Marcellus opportunity, both at significant scale and size, both highly profitable. And we're going to start scratching around looking for the third leg of the stool. One that would equal the margins we have in these two core legacy natural gas assets and give us our third legacy move forward in 2013 at the same time periods. We've actually spent a fair amount of times looking at number of the oil shale opportunities, other opportunity, and they just don't compare with the margins we have in the two current assets now. In some of those areas, we're probably coming in late and having to pay a higher acreage costs nonetheless. It backs us up and makes us realize how good a deal we did in the Marcellus acreage acquisition that we closed in February, and how we're improving upon those returns is because of the ability to add on acreage at lower cost adjacent to that and in our own backyard. So we're not wed to any commodity, one way or the other, we're wed to margins.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

In terms of the Marcellus, it sound like, Bill, you said you're looking to average 90 million a day for Q4. I think previously you had put out an extra rate number of 130 million a day. Just wondered if you're still comfortable with that, and if you're having any thoughts on change of plans there now that you got Shell as a partner. And have they given you any kind of idea on what their plans maybe?

William Picquet

Tackle those one at a time. As far as paying rate is concerned, we're more focused on what's our average rate. An exit rate is just kind of an instantaneous rate, and I think it's way more important to focus on what's happening is for q-over-q volumes are concerned and those average in it. I think we said we're expecting to see 60 million cubic feet a day net in Q3 and 90 million cubic feet a day net in Q4. So obviously, you have to have some pretty good producing rates to get there. And well adds might be lumpy because of pad drilling and that type of thing. And so at any given time, the daily rate is not nearly as significant as the quarterly rate. As far as Shell is concerned, they just closed yesterday. And we love a competition, and we compete with Shell as far as activity is concerned, and Pinedale and operating efficiency. And we kind of like the idea that they are going to be our partner in Pennsylvania, and we'll have the opportunity to have that competition once again.

Michael Watford

Let me help with this one too. We don't have any definitive budget plans for Shell for the remainder of 2010 or '11. It's sort of indicated that the ongoing east plans will be like skewed on the remainder of 2010. That makes sense. We've indicated they're going to change out rigs and go with a different rig count, bring the indicator probably even may change out completion competition. So there's going to be a little lag in there. That's what Bill noted earlier. But we're comfortable that they didn't spend almost $5 million buying this company, this asset, with a great deal of the value to the joint acreage we share. We're comfortable that we didn't spend that money with the idea of going slow. So we look forward to seeing what they're doing 2011 and '12.

Operator

Our next question comes from the line of David Heikkinen with Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

In the Marcellus, I know you guys have targeted that 340 million a day of gross capacity. Can you walk us through where you are in that capacity right now as far commitments for 2010, 2011, and kind of the operated and non-operated capacity as well?

William Picquet

We've kind of shared interconnect capacity with you over the course of time. And our updated numbers whereas totals are concerned were at about 565 now. We expect to exit the year at over 1.2 billion as far as interconnect capacities are concerned. And those timing's a little bit depending upon individual taps of various areas. That's where are turn has come from.

Michael Watford

If you want to know how much is operated by East or Shell and Anadarko and ourselves, there's about 200 million a day today operated by us, so that's 565. And that remains constant through the buildup of over 1 billion a day of interconnect capacity by year end.

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

And on that 2 million a day operated, you have about 50% of that on a working interest basis?

Michael Watford

That's 100%. I mean, what's going on, David, is there's a number of different gathering systems being built up in our 100% acreage. We're building a gathering system. And the interconnect is the Dominion currently, about 200 million a day. In the East, soon to be Shell, I guess it is Shell as of yesterday, there's three different gathering systems that are all partially built with interconnect. Caltex is on, its called Wellsboro. Those are all currently into Tennessee. And they all are in the process of being upgraded in terms of capacity in interconnect. And then Anadarko is, I don't know what the time of their's is, but they're also building a large gathering system and the properties will take it down south and that'll be a joint venture between ourselves and them. And the one with Shell would be a joint venture between ourselves and them.

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

And do they all have capacity expansion around compression and a typical ability to expand their heavy...

Michael Watford

Yes, absolutely. And as you would imagine, Anadarko wants to build theirs in such a fashion they can drop their -- 35% of it or so down into their MLP at some point in time. So we have to please theirs and we have 50% of it.

Operator

Our next question comes from the line of David Tameron with Wells Fargo.

David Tameron - Wells Fargo Securities, LLC

Mark, you talked about differential a little bit. Can you talk about what's going on right now? It seems like it's Opal's widen versus like a Henry Hub Gulf Coast price. I know you guys are price protected, but can you talk about just what you're hearing and seeing in the region et cetera?

Marshal Smith

Well, we're in the summer months. We haven't had a lot of demand on the West Coast. So that's effecting what we're seeing in the Rockies over the summer. And so you're seeing some expansion in margins as we move through some of these summer months that you alluded to.

Michael Watford

And I think what our marketing folks said just last week is, in Southern California, they're having the mile to summer they've had in, I don't know, 20 or 30 years. So obviously, there's less demand.

David Tameron - Wells Fargo Securities, LLC

Circling back to Marcellus. So Mike asked the question about your exit rates, and Bill, I agree that the exit rates don't matter. But just going back to the first quarter, you guys have exit rate of 130 million a day. Can you just give us any plus or minus that number?

Michael Watford

I think we're going to stick with the 90 million a day average production for the fourth quarter. It's just hard for us until we know definitively what Shell is going to do here or remainder of the year. It's hard for us to give you a better exit rate. So we're comfortable that the 90 million a day in the fourth quarter, a 20 Bcfe number for the year is probably a more representable number.

David Tameron - Wells Fargo Securities, LLC

Any 2011 number you care to give us, so I can come back later and try to hold you to it?

Michael Watford

I think we've been known to say 20 Bs of Marcellus production in 2010, 70 Bs in 2011 and 100 Bs in 2012. I don't think you're going to see us backward from these numbers right now.

David Tameron - Wells Fargo Securities, LLC

And when we hear the 20% for 2011, is that 70 B inclusion with the net number?

Michael Watford

We're talking about a 20% increase in overall production year-over-year. Yes, that Marcellus component is part of that, yes.

Operator

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

Ronald Mills - Johnson Rice & Company, L.L.C.

You talked about the Shell plans, which at this point, sounds like more aligned to what East had planned. But now that the Anadarko-Mitsui deal has been in place for quite some time, have you seen any market difference in activity levels from what Anadarko had planned on a standalone basis versus with Mitsui in place? Or what the outlook is?

Michael Watford

Well, I don't know that Mitsui-Anadarko deal has been in place very long, Ron. I think maybe it's March or April.

Ronald Mills - Johnson Rice & Company, L.L.C.

But it's been closed for more than one day, right?

Michael Watford

Right. I mean, we're seeing some differences or changes with Anadarko being more aggressive. Post the Mitsui closing, I think the answer is no. I think there's a lot of things going on in Anadarko right now. Obviously, there's been some issues in the Gulf, but they also have Mitsui's monies in Marcellus. Our anticipation is that they're going to continue to do their five rigs that are operating now, just like the fifth one. But our preliminary plans for 2011 will continue to five rigs that we're indicating that they're going to grow from there. That's five. They want to get the infrastructure built. And the problem they have right now, or not the problem but their issue is, they don't want to get too far ahead in drilling their wells before they get their infrastructure built. There's a tremendous amount of the pipeline as we speak their progression. Those will happen in the next eight weeks, and I think we'll get a better feel when they go through their budgetary process for 2011 and what level of activity, catching the perpetrators. What level of activity they're going to have in 2011. We don't see anything less than that. If anything, we see increasing activity.

Ronald Mills - Johnson Rice & Company, L.L.C.

And in Marcellus, obviously, the second quarter, you had 20 of the 21 wells either to date come online. Is that a function of just getting beyond the stream crossing permits and having cap sites in place? And so going forward, from a timing standpoint, should the completions kind of proceed in a more orderly fashion rather than some of the delays experienced late last year or earlier this year?

William Picquet

I think that's accurate as far as both cases are concerned. Permit base is getting much more predictable. We got a lump of stream crossing permits all at once that allowed us to proceed forward with installing a lot of gathering and that was through our Eastern and EMEA as well. And we're well positioned to go forward as far as ability to build and have a more steady pace as far as adds are concerned on producing levels.

Michael Watford

Bill, how far ahead are we on permitting now?

William Picquet

We have all the permits that we need to execute the remainder of 2010's programs, and we're concentrating on 2011 at this point.

Michael Watford

I think that's a case with East/Shell. I guess we know less than Anadarko, but the Shell folks and our people are well positioned to execute with permit.

Ronald Mills - Johnson Rice & Company, L.L.C.

Just on your three-year plan. When you all spoke about that initially, the expectation is still in place that as we go through 2011 and '12 that by the end of next year, you're back on track to be in self-funded and generating excess cash flows and then x any significant changes in activity plans?

Michael Watford

Right. I think our internal plan is to have an EBITDA in 2012 of $1.4 billion, $1.5 billion, based on where 2012 gas prices are now. And we won't be spending it at that rate. So yes.

Operator

Our next question comes from the line of Michael Bodino with Global Hunter Securities.

Michael Bodino - Global Hunter Securities, LLC

I just have a couple of Marcellus follow-up questions. Can you give us a sense of the rig count and how much of it is allocated to a pure development where it's pad drilling, wells being hooked up? And how much of it is being allocated toward really holding acreage, exploring kind of that other amount of property that you've been picking up?

Michael Watford

Let me start and then Bill will fill in. If we break our acreage there into three components by operator, let's start with the Anadarko first, none of the gathering system built are associated with the Anadarko-operated properties, they're making their acreage protection, because 92% of it was held by production and we acquired acres that we picked up around there. There's acreage with 10-year terms. And so that's really whatever development programs that there is all about economics. The East soon to be Shell opportunities has some acreage issues there, and I'd say, probably half of the cost this year are going towards -- really more than half of the costs go towards drilling acreage, it's kind of whole production. And there's not a lot of pad drilling going on. That's why we're still comfortable that our well cost aren't going to increase too much, given what's going on in the pressure pumping side. And then in our fees, I'll let Bill comment on that one.

William Picquet

Our fees, very small portion, only a couple of wells are targeted toward holding acreage. The rest of it is all horizontal development activity. By year end, we'll have a significant portion of our acreage held, and then the expiry starts stretching out beyond that. That's the status on the operating side.

Michael Bodino - Global Hunter Securities, LLC

Kind of a follow-up question. Given that, how do we think spud to sales with rigs that are running for the second quarter then as we move through the rest of this year into next year?

Michael Watford

We've had terrible spud to sales, Michael, up to this point in time because of lack of gathering infrastructure. So we're going to -- I don't know that I want to give you a number yet till we have -- with the quarter of history of what we think is going to happen with ourselves and Shell and Anadarko going forward. I'm just going to back away from it.

Operator

Our next question comes from the line of the Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann & Company

I wanted to ask you about hedges. So you had about 60% mark for 2011. What's your appetite for hedges going forward? Do you think you'll leave it there just to make -- any upside we might see in gas prices looking that far out? Or are you more likely would be conservative and look under the margin more.

Marshal Smith

I think we feel pretty good about where we are for 2011. And we'll monitor anything else whether it's 2011 or 2012 based on market conditions as we move forward.

Noel Parks - Ladenburg Thalmann & Company

And also looking your new ventures group tax received in general. What's your thoughts on all of these stock deals that we've seen over the past, I guess, year and maybe year and a half now? You guys certainly have the balance sheet to do whatever you'd want to in cash. So I'm just looking for some comment on just what your financing thoughts might be?

Michael Watford

I'm going to help Mark. If you're asking, are we going to issue equity? The answer is not likely. No. If you look at it over time, we shrunk our equity, so we'd have to be a heck of an opportunity for us to issue any equity.

Noel Parks - Ladenburg Thalmann & Company

And also, looking ahead, would you consider something international again, thinking about your China experience two years ago?

Michael Watford

I think something in the Caribbean islands would be really nice. We wouldn't shy away -- if we go back in the history of the company, we had a nice interest in some offshore China, production and operating Anadarko. And since we couldn't get any more scale and more size after it was mature and we sold it just to the cash in our pocket made nice profit. If we had another international opportunity that had scale to it, that we could get scale, then that would be fine. We're not nervous about international risks.

Noel Parks - Ladenburg Thalmann & Company

I'm sure you've already got such a long researchers reserve like just from what you have and you gave us some more detail on where your location comes then. Looking for whatever you might acquire, do you have a preference for trying to add even a longer-term growth thread wedge to your profile? Or are you thinking more about acquisitions that might steepen what you achieved, say, in the foreseeable year, say, over the next five years, hiking up that growth rate even more. Just trying to get a sense of kind of how grass root sort of stuff is that you might be thinking about?

Michael Watford

Well, I don't think our reserve are less at all. And I think the effort behind creating a new ventures group and staffing it with exploration is clearly that to go out and look for exploration opportunities, low cost opportunities, where we get scale. It's not really to go out and look at producing property opportunities where we can get the highest price and win the day, much like the excess earlier this year of land only, the production of reserves in Marcellus. So our focus is all about we're going there to make money. That probably is more exploration-oriented where the cost of entry early on isn't expensive and with a lesser grade. So I think that way we can sever some additional risk.

Noel Parks - Ladenburg Thalmann & Company

Assuming success though, you'll be looking to push out sort of your visibility for long-term production growth even further that you have it now then?

Michael Watford

Well, I don't think people quite understand the assets we have, controlled by our 101 employees now. Yes, we did break the 100 employee barrier. And the ATC has, I mean, 12 fees and probably I think they'll increase in Pennsylvania and Marcellus so you may have some doubters. But we've added another 30,000 acres as we up that number. And we think we're going to be down spacing from 80 acres spacing. So we think reserves probably goes up over time not down. So we have, again, $25 billion, $26 billion of future development capital ahead of us. Do we need more? Not today, but it will truly get our cash flow and EBITDA to $1.4 billion, $1.5 billion, maybe $1.6 billion if gas prices strengthen in 2012. Our ability to churn through that increases and we're just trying to plan for the future, have more resource with attractive margins. That's the goal.

Operator

Our next question comes from the line of Brian Corales with Howard Weil.

Brian Corales - Howard Weil Incorporated

On the Marcellus production, I guess you talked about 70 Bs or so for 2011. Are just assuming, with the non-opposition, the activity remains flat?

Michael Watford

Pretty much, but I'll let Bill correct me. I mean, flat, I think we're assuming in that preliminary number. Again, we're not trying to provide a lot of detailed guidance for 2011 yet. But that's preliminary number, I think it assumes about five rigs by Anadarko and three by Shell and one by us. So yes, pretty much flat.

Brian Corales - Howard Weil Incorporated

So I mean, you could see some increase if Shell decides to go a little faster?

Michael Watford

Right. We're trying to live by our old tradition of under-promising and over-delivering.

Brian Corales - Howard Weil Incorporated

And how much of that production would be company-operated? Is it about half?

Michael Watford

Probably not. It looks like a capital budget for a second. I don't know a thing about production volumes, I'll let Bill think about that while I'm getting some time. But capital budget in 2010, we have about $440 million for drilling completion and infrastructure in Pennsylvania. It's 30% operated and 70% non-operated plus or minus. And going forward in 2011, I don't think our model probably has a changing sum with a little more outside operating frankly.

Brian Corales - Howard Weil Incorporated

You all mentioned before about kind of closed end water system and kind of best practices in the Marcellus. I mean, is this something that's being done by other operators and has it kind of pushed? We've seen a lot of talk from regulators. Do you think this will be adopted by the rest of industry?

William Picquet

Yes, I think that it is starting to be. I think that other operators are reacting to the fact that the use of water is probably more economic than trying to find a place to dispose of it. And we think over the course of time, there'll be a mix of all of that because play will evolve and it's basically just a push to the best economic solutions.

Michael Watford

Let me go a little further. We're a little different than some of the other Marcellus players and our maturation process occurred in Pinedale, Wyoming largely in federal acreage. So we have the good blessing of having oversight by all the state regulators and all the federal regulators. And because it is public lands, we reach lots of public groups that has helped manage our business for us. And because of that increase through Dominion and regulation and the reduction of pad sizes, surface issues or initiative access et cetera, we are used to dealing with a maybe with the hurdle of overall regulations and environmental issues being a little higher. So although we worked very closely with the Pennsylvania authorities and the other companies active there haven't had the same level of oversight that we've in Pinedale. So I think we're finding -- we just brought that, I'm going to call it, best practice, we brought that best practice with us. The East is doing the same thing. I'm sure Shell will add to that. But when we build the gathering systems, and we build our gathering systems, we put pipe in the ground of new water too. Anadarko has indicated they're moving in that direction. So we haven't any of the water issues. Quite frankly, we don't understand why people keep asking these questions because we just approach it differently than others that haven't had the lovely experience on federal lands may have a different view. I will take one more step. What do we do in the well construction up there, Bill?

William Picquet

The recent discussions as far as well construction is concerned, with DEP implementing regulations that would require additional protective strings of shallow water. We were doing that before they started discussing it, anticipating the fact that that was going to be an issue just from observations. We started that essentially from day one and our operations in Pennsylvania. So there's no change to us. Those who may be talking about a potential uptick in cost as a result of that, we're not.

Operator

Our next question comes from the line of Nicholas Pope with Dahlman Rose.

Nicholas Pope - Dahlman Rose & Company, LLC

In terms of modeling going forward, capital cost accruals you have, it looks like it creeped up a decent amount in the past few quarters and the same thing with just accounts payable. And trying like that piece of working capital going forward. If we should expect that to be more steady state going forward or is there more kind of imbalance we should expect for a few quarters.?

Marshal Smith

Those are just working capital issues as you indicated, and so we spend a little bit more in the field, you're going to get -- as capital cost accruals are just moneys we believe we spent that just haven't necessarily hit yet. So it's a function of activity levels.

Nicholas Pope - Dahlman Rose & Company, LLC

I guess just in terms of projecting those working capital numbers, I mean, it just seems the past few quarters that we've seen that increase. Should that kind of reach a steady state at some point or....

Marshal Smith

If you're forecasting like our outlook is indicating, with relatively CapEx over the next period of time, you should see those numbers stabilize.

Operator

Our next question comes from Ray Deacon with Pritchard Capital.

Raymond Deacon - Pritchard Capital Partners, LLC

Bill, I was wondering how much would you estimate fact cost have increased since the beginning of the year in the Marcellus? And how is the availability of frac for us?

William Picquet

Well, percentage-wise, I'd say in excess of 30%. It would be a typical number as far as an increase is concerned. And that's just the cost of services. We're seeing efficiency gains that will offset a portion of that and how we approach it. So we're not sure where that would land as far how overall costs reacts yet, but we think that's a pretty wide spread issue as far as the industry is concerned. Availability of services is also very tight. And so far we're not experiencing any difficulty in the pace of completions in our operations resulting from that but we are seeing that tighten up and it's going to remain tight for a while I think.

Raymond Deacon - Pritchard Capital Partners, LLC

Do you think that the condensate pricing relationship this quarter, I guess Pioneer had mentioned yesterday they thought the next couple of years they were comfortable that condensate and liquids pricing would be okay, but they were a little concerned about hedging beyond that. I was just curious what your thoughts were on that?

Michael Watford

Our condensate is produced in Wyoming in the Rockies. And I guess I don't have much of an opinion on -- Mark's going to go in. I'm just happy where it is today.

Raymond Deacon - Pritchard Capital Partners, LLC

I was curious what are your competitors, ETT, put out a decline curve for the Marcellus for the first time yesterday and they are showing somewhere around 2 million a day of production in the first year and about 1 million a day in year two. And I guess, based on what you guys are seeing so far, are your results kind of roughly looking like that?

Michael Watford

Bill can answer here, but unfortunately, we don't have two years of history yet and we barely are near some wells. They have more data than we do.

William Picquet

Operating in a different area.

Operator

Our next question comes from the line of Subash Chandra with Jefferies.

Subash Chandra - Jefferies & Company, Inc.

Not quite to play devil's advocate here, but with optimal drainage and some of the bigger technical questions, where the lateral county by county or area by area, more precise targeting. Without having those questions answered, why entertain a dramatic spike in drilling anyway? You're drilling a lot of wells. These answers didn't sound like they were in hand jet. So you're doing the science. So why drill 50 or 60 more wells this year? And I think you set a fraction of those would be for holding acreage. Why drill so many more or at least have that in the budget right now, drill so many more in future years before having those questions answered?

Michael Watford

Let's just do numbers for us. If we're going to drill between us and our two partners, 107 wells this year. And as we've already identified locations of 2,300 wells and that does an equivalent of 3,000 acres and that's only 6% of the total. So I don't that it's a significant number. But secondly, you have to have reasonable sample population across the acreage to better do what you're asking us to have a handle on in order to understand how we locate the wells, how to steer the wells, how we frac the wells, that's why we're on to our second microseismic efforts here, already done one and we know Anadarko is going to do one. So again, we learned about spacing, learned about how to frac the wells. All that's ongoing to make sense to spend a little less than an extended period of time, maybe. But we're comfortable that our 2,300 net well count, that's not the gross well count. It's a smaller percentage. There were 5,000 gross well, so it's about 2%. And we just want to get a rate case of learning process. And even at today's gas prices in Marcellus, we have outstanding returns. We have continued to hedge in 2011. I think our average eastern market hedge price for 2011 is over $6. You've seen the return slide in our handout and those are assuming a 5% severance tax in Pennsylvania. We would agree with anyone to discuss the capital costs by go up and drilling, but we have so much headroom for making money, it just makes sense for us to go ahead and start spending money and probably the argument here is to accelerate development.

Subash Chandra - Jefferies & Company, Inc.

In some of the developing places, if we don't know whether it be 100 acres or 50 acres, that's probably easy because you can put a well right in the middle, but if two numbers 80, kind have one shot at that in getting those two wells done. If simul fracs matter, if things like that matter, you kind of have one shot at that. Whereas if you kind of drill down through then it'll be hard to come back into the optimal training. Is that fair or is that an overstatement?

Michael Watford

We're going to try to do these ideas. That's what we're doing now but I don't know if you're overstating anything.

William Picquet

We emphasize the importance of gain, the information currently into play and determining spacing and lateral length and that's what we're doing.

Subash Chandra - Jefferies & Company, Inc.

In the Pinedale, have you done the math this way that if you -- how much rig cost for the year and what sort of well price would be break even for that rig? I know there's a net income approach but I was curious if there was the CapEx per rig type of approach you might have done?

Michael Watford

We know what our capital is, and again it has to do not with absolute cost but what your net cost is, so where you drill. Are you drilling in areas where you have 75% ownership or 50% ownership. And what kind of wells you're drilling. For example, I'll contrast us with probably what Equistar is doing right now. All our wells are over six that we drill in the second quarter and we're at $4.6 million of well cost. Their wells as less than 3 Bs, and their well cost are less than that because of reduction of frac cost. But if you let talk about effectiveness of your program, I'd rather be drilling the 60 wells. So yes we look at our return on capital in all the wells we won't drill 2 B wells or 2.5 B wells to find out they're not economic. But we have so many wells to drill and we went through this analysis last year and gas prices were quite a bit lower in Pinedale. That's the other thing I don't think people are paying attention. Our unhedged gas price, our spot gas prices in the Rockies, are almost $4, $3.80, $3.90 today. This time last year, they were $2.70. Until last year, we were far more fearful of investment decisions and trouble that's why we went from 15 operator rigs in late 2008 to five in 2009. And now we're at seven. And we just make money at $4. So there is a reason for us not to go forward.

Operator

[Operator Instructions] Our next question comes from the line of TJ Schultz with RBC Capital.

TJ Schultz - RBC Capital Markets

You guys had 21 wells to sail in the first half of Marcellus. Correct me if I'm wrong, but I think you had said 95 by year end. Just looking into the second half of the year, can you kind of walk me through the pace of getting those to sale. I know production must be pretty steady increase in Q3 and Q4. Should we look at it getting this well for sale as a pre-state increase as well?

William Picquet

I think that the production increase speaks for pace of wells. I don't want to just try to quote you quarter by quarter or month by month well addition, but we're confident that we can hit those production volumes.

Michael Watford

And there'll be more on in the fourth quarter than the third quarter. So it ramps up over the course of the year.

TJ Schultz - RBC Capital Markets

Can you give a current production number in the Marcellus right now?

William Picquet

It is at about 55 million a day net and over 100 million a day gross as of today.

Operator

Ladies and gentlemen, this will conclude the Q&A portion of the call. I would now like to turn the call over to Michael Watford for closing remarks.

Michael Watford

Thank you. If you have any additional questions, please don't hesitate to call or e-mail the fine ladies in the Investor Relations group. Thank you very much. Bye.

Operator

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

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