Hiland Partners, LP. Q3 2009 Earnings Conference Call

Hiland Partners, LP. (HLND)

Q3 2009 Earnings Call

November 06, 2009 11:00 a.m. ET

Executives

Derek Gipson - Director, Business Development and IR

Joe Griffin - President, CEO and Director

Matt Harrison - VP-Finance, CFO, Secretary and Director

Analysts

David Fleischer - Chickasaw Capital Management

Eric Conklin - Harvest MLP Funds

Presentation

Operator

Good day ladies and gentlemen, and welcome to the third quarter 2009 Hiland Partners LP and Hiland Holdings GP, LP earnings conference call. My name is Eric, I’ll be your audio coordinator for today. At this time all participants are in a listen-only mode. We will facilitate the question-and-answer session at the end of the presentation. (Operator Instructions). As a reminder the conference is being recorded for replay purposes.

I would now like to turn the presentation over to Mr. Derek Gipson, Director of Business Development and Investor Relations, please proceed.

Derek Gipson

Thank you Eric, good morning everyone. We appreciate you joining us for the Hiland Partners LP and Hiland Holdings GP, LP conference call to review financial and operating results for the third quarter of 2009. If you would like to be on our list to receive future press releases via email distribution or fax or if you experience a technical problem did not receive the copy of the earnings press release issued last night, please give us a call. Our investor relations phone number is 1580-242-6040. A replay of the webcast will be available later this afternoon on our website. Access details are provided in the Press Release.

With me this morning is Joe Griffin our President and Chief Executive Officer and Matt Harrison our Chief Financial Officer. Please note that the information reported in this call speaks only as of today November 6, 2009. Therefore time sensitive information may no longer be accurate as the date of any replay. Our discussion today may contain forward-looking information as based upon management’s beliefs and assumptions, and are also made based upon information that’s currently available to management.

Although the company believes that their expectations reflected in such forward-looking statements are reasonable, we can provide no assurance that such expectations will prove to be correct. Such statements are subject to certain risks, uncertainties and assumptions. One or more of these certain risk materialize or should, the underlying assumptions prove incorrect, actual results may vary materially from those expected.

These risk as well as others are discussed in greater detail in the partnerships annual report on Form 10-K, or other documents filed from time-to-time with the Securities and Exchange Commission. Please note in this call we use the terms distributable cash flow, EBITDA, adjusted EBITDA, total segment margin. These are non-GAAP financial measures and we have provided reconciliations to its most directly comparable GAAP measure in last night’s earnings press release.

Each of Hiland Partners and Hiland Holdings on November 3 entered into amended merger agreements with affiliates of Harold Hamm. As we intent to follow proxy settlements the definitive joint proxy statement with the SEC that will contain important additional information regarding the Hiland merger agreements, we will not address on this call depending mergers or taking questions regarding the depending mergers. We refer your statements on previous filings concerning the mergers. Joe will begin the call with some advance comments regarding on our earnings press release covering our third quarter 2009 results. Matt will then provide the detailed analysis, then we will address your questions.

With that I’ll turn over to Joe.

Joe Griffin

Thank you very much, Derek and good morning. I appreciate everybody turning in for our call this morning. I though as usually will cover a few industry statistics as well as some operating stats to give you a little bit of background before Matt works into the numbers.

So, in comparing the third quarter’09 to third quarter ’08 results, the WTI last day’s settled average for the third quarter of ’09, was $68.29 a barrel, and that compares to $125.85 a barrel for the third quarter of ’08. That’s a decrease of $57.56 per barrel or 46%. With regards to the Henry Hub the average of the last days’ settle for the third quarter of 2009 was $3.44 that compares with $10.24 for the third quarter of ’08. That’s a decrease of $6.80 or 66%. On the regional pipeline basis side, we did see some significant tightening and basis which will be positive for our operating results. Colorado Interstate Gas or which we refer to as TIG, the basis average for the third quarter of 2009 was $0.77. That compares to $4.34 differential in the third quarter of 2008. That’s an improvement of $3.57 per MMBtu or an 82% tightening. With regard to Panhandle Eastern the basis for third quarter of 2009 was $0.53. That compares to $1.91 for the third quarter of 2008. That’s a tightening of $0.38 per MMBtu. At CenterPoint East which drives our Oklahoma basin system operations Kinta and the Woodford system that basis for the third quarter of 2009 was $0.47 back, compared to $1.83 back in the third quarter of 2008, that’s also an improvement of $1.36.

With regards to our indices, four of those areas, they were down significantly compared to the third quarter of 2008 has primarily due to the decrease in the Henry Hub partially offset by some improvements in basis. For CIG the industry average for the quarter was $2.67 compared to $5.90 for the third quarter of 2008. That’s a decrease of $3.23 per MMBtu. For Panhandle Eastern which primarily reused the benchmark to drive our western Oklahoma operations. The index was $2.91 for the third quarter of 2009. That compares to $8.33 for the third quarter of 2008. That’s a decrease of $5.42 per MMBtu.

And CenterPoint East the index averaged $2.98 for the third quarter of 2009, and that compares to $8.41 for the third quarter of 2008, also a decrease of $5.43 per MMBtu. With regard to NGL prices the Opus convey simple arithmetic average per gallon price from the third quarter of 2009, averaged to a little over $0.90 per gallon, that compared to $1.71 per gallon in 2008. That’s a decrease of $0.81 per gallon.

With regards to Mont Belvieu with simple arithmetic average for the per gallon price was of $1.01 for the third quarter of 2009. That compares to $1.85 from the third quarter of 2008, that's a decrease of $0.84 of gallon. With regards to growth processing commodity spreads before applicable transportation and fractionation charges. The spread based on the convey prices for CIG with $6.38 per MMBtu that compares to a gross process and commodity spread of $11.73 per MMBtu for the third quarter of 2008.

That’s a decrease of $5.35 per MMBtu. With regards to Panhandle Eastern the gross profits and commodities spread before TNS charges was $6.14 per MMBtu for the third quarter of 2009, and that compares to the third quarter 2008 spread of $9.30 per MMBtu. That’s a decrease of $3.16 per MMBtu.

With regards to some operating statistics, I think its important to note that our inlet natural gas volume on a per Mcf per day basis for the third quarter of 2009 was 257,950 Mcf per day, that compares to 261,000 Mcf per day, little over 261,000 Mcf per day for the third quarter of 2008.

That’s a decrease of about 3,400 Mcf per day on a quarter-to-quarter comparison with decrease of 1%. And I have some more comments about our volumes later on during the call. Our NGL sales on a barrels per day basis was 7115 barrels per day for the third quarter of 2009, that compares to a little over 6000 barrels per day for the third quarter of 2008. Some positive increase of about 1000 barrels per day or 18%.

With regards to well connects, I want to give you some stats for all of our systems excluding our North Dakota Bakken system that was commissioned in April of ’09, I think that’s an important reference point. And then we’ll talk about the North Dakota Bakken System as well. With regards to well connects, excluding the North Dakota Bakken system, we connected three wells company wise and during the third quarter of 2009 and that compares to 28 wells during the third quarter of 2008, that’s a decrease of 29 wells or 89% in activity.

With regards to North Dakota Bakken system that we commissioned in April 2009, we connected nine casinghead wells for the system during the third quarter of 2009. With regards to average realized natural gas prices on per MMBtu basis during the third quarter, our average realized price was $3.25 per MMBtu that compares to $7.57 per MMBtu, that's a decrease of $4.32 per MMBtu between the two quarters.

With regards to average NGL sales price on a per gallon basis, we realized $0.76 per gallon for the third quarter of 2009 and that compares to a price of $1.55 per gallon for the third quarter of 2008, that’s a decrease of about $0.80 a gallon. With regards to some year-to-date statistics, and looking at '08 compared to nine months ended through 9/30/09 compared 9/30/08. I think it’s important to just look at a few offering statistics. For the year, we are still ahead on throughput, our Hiland natural gas volume is about 269,000 on a day year-to-date. And that compares to 245,000 Mcf per day year-to-date for '08. That’s well about 24,000 Mcf per day or 10% increase.

With regards NGL sales on a barrels per day basis, year-to-date for ’09 was 7,141 barrels per day, that compares to 5,763 barrels per day for the year-to-date '08 numbers. That’s an increase of 1,378 barrels per day and also a positive year-to-date variance.

With regard to well connected activities again excluding our North Dakota Bakken system, year-to-date we have connected 26 wells company wide and that compares to 83 for the same period last year. That’s a decrease of 57 wells or 69%.

And as we mentioned on the North Dakota Bakken system which was commissioned in April we currently have 41 wells connected to the system. With regards to realized prices year-to-date for natural gas, our year-to-date realized price is $3.32 per MMBtu that compares to $8 per MMBtu for nine months ended September 30, '08, a decrease of $4.68 per MMBtu of 59%.

And with regards to average realized NGL prices, we averaged year-to-date $0.67 per gallon for NGL sales and that compares to $1.53 for the same period in calendar ’08. That’s a decrease of $0.86 per gallon or 56%.

With regard to capital expenditure year-to-date, our growth capital expenditures are about $19.3 million that compares to $33.3 million of nine months into ’08, the decrease of about $14 million or 42%. With regard to maintenance CapEx year-to-date we have spent about $4.13 million that compares to about $4.7 million for the nine months ended ’09, to decrease of a little over $0.5 million.

With regards to the contract mix for the third quarter of 2009, our midstream segment margin was comprised of about 49.5% a percentage of proceeds contracts with incremental fees about 32% was comprised of percentage of index and index minus contracts with [keyhole] margins and about 18.5% was fixed [fee] gathering charges.

If you look at where we are at the end of the third quarter with regards to our cabinets in our credit facilities, we ended the third quarter 2009 with interest coverage of 4.94 that is in compliance with our credit facility which has a greater than 3.0 requirement. Our leverage ratio was 4.49 as you will recall, we invited the step up at the end of the first quarter and we can go as high as 4.75. We do however have to have that down to 4 or below by the end of this year.

With regards to the LP credit facility this 300 million available on that facility at the end of the third quarter we had $253 million drawn so that left us with about $47 million of available credit under that facility. And I do think it's important to note that we paid down $8 million during the third quarter of 2009.

GP credit facilities reported in our last earnings call out of total available now is $3 million, that $3 million has been fully drawn. And so we have no capacity as of the end of the third quarter but as we announced in our press release earlier in the week, we have entered into a transaction that has been improved by our conflicts to many in our board of directors, where our chairman Harold. Hamm has agreed to lend us some working capital to give us through to the end of the year.

With regards to the mark-to-market value of our commodity derivatives at the end of the third quarter they are in the black about $3.9 million, we are pleased with that. The mark-to-market value on our interest rate swaps is about $0.5 million out of the money but does not as we've managed that as we move forward.

And the another comment I might have, as you noticed in this morning's press release, we had a significant non-cash charge property impairment and that was attributable to our Kinta system. And to give you a little bit of history of the Kinta system as you know that was acquired in May of 2006 for a little over $96 million. The Kinta system is primarily a vertical gas play that covers debts ranging from 2000 feet as deep as 12,000 feet and beyond. This gas is clean as a whistle it typically comes in at 990 Btu to 1000, extremely lean. And typical we have CO2 content in excess of 2% but the system is not driven by crude oil prices or NGL prices.

And unfortunately it’s been seriously hurt by the low year-to-date gas prices that we have seen this year. And doing the impairment analysis we were not able to benefit from the increases that we have seen in NGL prices during the second half of the year. And so it was a significant non-cash impairment charge and we just make sure that we address that before Matt gets into the numbers. And with that I think I will go ahead and turn the call back over to you Matt.

Matt Harrison

we will cover the results of Hiland Partners LP first. Adjusted EBITDA for the three months ended September 30, 2009 was $15.5 million compared to $18.6 million for the three months ended September 30, 2008 a decrease of approximately 17%. Total segment margin for the same comparative period was $24.6 million for the third quarter of 2009 compared to $33.9 million for the third quarter of 2008, a decrease of approximately 27%. The decreases in adjusted EBITDA and total segment margin are primarily due to unfavorable growth processing spreads significantly lower average realized natural gas and NGL prices. And overall decrease in natural gas sales volumes offset by an overall increase in NGL sales volumes.

It should be noted that a percentage of mid-stream revenues that mentioned segment margin was 44% for a three months ended September 30, 2009 compared to 29% for the three months ended September 30, 2008 an increase of 15%. This percentage increase is attributable to the positive impact of fixed-fee arrangement contracts, which are not affected by realized natural gas and NGL selling prices.

Improvements in third party processing arrangements at the Woodford Shale gathering system, increased volumes under favorable percentage of proceeds, contracts at the North Dakota Bakken and Badlands gathering systems and gains on closed, settled derivative transactions and unrealized non-cash gains and open derivative transactions for three months ended September 30, 2009 totaling $2.2 million, compared to net losses of $1.4 million for the three months ended September 30, 2008.

And this is offset by an unrealized non-cash of $5.6 million relate to a non-qualifying mark-to-market cash flow hedge for forecasting sales in 2010 which impacted our three months ended September 30, 2008 numbers. Average realized natural gas sales prices for $3.25 per MMBtu for the third quarter of 2009 compared to $7.57 per MMBtu for the third quarter of 2008, a decrease of $4.32 per MMBtu.

Net cash received from our counterparty and cash flow swap contracts for natural gas derivative transactions for the third quarter of 2009 was approximately $2.5 million compared to $1.1 million for the third quarter of 2008. This gain increased average realized natural gas sales prices in the third quarter of 2009 to $3.25 per MMBtu from $2.94 per MMBtu, an increase of $0.31 per MMBtu.

Average realized NGL sales prices were $0.76 per gallon for the third quarter of 2009 compared to a $1.55 per gallon for the third quarter of 2008, a decrease of $0.79 per gallon. We had no cash flow swap contracts for NGL derivatives during the three months ended September 30, 2009 and 2008 cash paid for counterparties on cash flow swap contracts for NGL derivative transactions for the third quarter was $2.5 million, which reduced the average realized NGL sales price for such a period by $0.10 per gallon.

The net loss per Limited Partners unit basic for the third quarter of 2009 was $2.05 per unit, and this is based on Limited Partners interest in the net loss of $19.2 million and weighted average Limited Partners units outstanding of $9.4 million. Net loss in the third quarter of 2009 was at $20.5 million non-cash property impairment charge related to the partnership at the Kinta area gathering system. Excluding this charge net income for the third quarter would have been $1.3 million or $0.14 per Limited Partners unit basics.

Moving on to nine months data, adjusted EBITDA for the nine months ended September 30, 2009 was $43.5 million compared to $53.2 million for the nine months ended September 3, 2008 a decrease of about 18%. Total segment margin for the same comparative period was $68.8 million for 2009 compared to $84.1 million to the nine months ended September 30, 2008, a decrease of approximately 18%. The decreases in adjusted EBITDA and total segment margin are primarily due to unfavorable gross profits and spreads. Significantly lower average realized natural gas and NGL prices and overall decrease in natural gas sales partially offset by an increase in NGL sales volumes at approximately 2.3 million forgone margin as a results of the nitrogen rejection plant at the Badlands gathering system being taken out of our service due to procurements that you are doing at three months ended March 31, 2008.

And the percentage of midstream revenues midstream segment margin with 42% for the nine months ended September 30, 2009 compared to 25% for nine months ended September 30, 2008 and margin increase of 17%. This increase is attributable to the positive impact of fixed fee arrangement contracts which were not affected by realized natural gas and NGL selling prices. Improvements in third party processing arrangement at the Woodford Shale gathering system increased volumes under favorable percentage of proceeds contracts at the North Dakota Bakken and Badlands gathering system and gains on closed, settled derivative transactions in unrealized non-cash gains on open derivative transactions for the nine months ended September 30, 2009 totaling $7.1 million compared to net losses of $6.4 million on such contracts.

And for the nine months ended September 30, 2008. And this was offset by unrealized non-cash gain of $3.6 million related to a non-qualifying mark-to-market cash flow hedge for forecasting sales of 2010. Onto sales prices, average realized natural gas sales prices were 3.32 per MMBtu for the nine months ended September 30, 2009 compared to $8 per MMBtu for nine months ended September 30, 2008 a decrease of $4.68 per MMBtu.

Net cash received from our counter party and cash flow swap contracts for natural gas derivatives transactions, for the first nine months of 2009 was approximately 7.3 million, compared to 1.4 million for the first nine months of 2008. This gain increased averaged realized natural gas sales prices to $3.32 for MMBtu, from $3.2, an increase of $0.30 for MMBtu.

Average realized NGL sales prices were $0.67 per gallon for the nine months ended September 3, 2009, that compares to $1.53 per gallon to a nine months ended September 30, 2008. A decrease of $0.86 per gallon. Again, we had no cash flow swap contracts for NGL during the nine months ended December 30, 2009. Cash pay to our counter party on cash flow swap contracts for NGL. Derivative transactions that closed during the nine months ended September 30, 2009, totaled 7.9 million. Net loss for the nine months ended September 30, 2008 reduced averaged realized NGL prices to $1.53 per gallon, from $1.64 per gallon, a decrease of $0.11 per gallon.

Net loss for limited units basic for the nine months ended September 30, 2009 with $2.45 per unit, this is based on limited partners’ interest and net loss of 22.9 million in weighted average limited partners units outstanding of 9.3 million units. Net loss for the nine months ended September 30, 2009, excluding the non-cash property impairment charges of $21.5 million was 1.5 million or 16% for limited partners unit basic. As Joe spoke about for the nine months, but for the third month, three months maintenance capital expenditures for the third quarter of 2009 were approximately 1.3 million. Expansion capital expenditures for the third quarter of 2009, were approximately $2.9 million and distributable cash flow was $11 million.

On April 27, 2009, we announced the suspension of quarterly cash distributions on common and subordinated units beginning with the first quarter distribution of 2009. On the terms of the partnership agreement the common units will carry an arrearage of $1.35 per unit representing the minimum quarterly distribution to common units for the first three quarters of 2009 that must be paid before the partnership can make distributions to the subordinated units.

We had $253 million of debt outstanding under our credit facility of September 31, 2009, the borrowing capacity under our credit facility is $300 million. As Joe mentioned, we paid down $8 million of debt in the third quarter of 2009. I’ll briefly talk now about Hiland Holdings GP, LP, the limited partners’ interest and the net loss for the third quarter of 2009 was $12.4 million or $0.57 per limited partner unit basic, and that’s based on weighted average limited partners’ unit outstanding of $21.6 million. This compares to limited partners’ interest in net income of $11.2 million for the third quarter of 2008. Net loss was $20.5 million in the third quarter of 2009, as compared to net income of $18 million for the same period in 2008.

The limited partners’ interest and net loss for nine months ended September, 30 2009 was $17.8 million or $0.82 per limited partners unit basic and that’s based on weighted average limited partners’ units outstanding of $21.6 million as well. Compared to limited partners’ interest in net income of $10.9 million for the nine months ended September 30, 2008. Net loss was $27.6 million for the nine months ended September 30, 2009 as compared, to net income of $15.3 million for the nine months ended September 30, 2008.

As previously mentioned on April 27, 2009 Hiland Partners announced the suspension of quarterly cash distributions on a common and subordinated unit beginning with the first quarter distribution of 2009 under the terms of the Hiland Partners partnership agreement, Hiland Partners’ common units were carrying arrearage of $1.35 per unit which represents the minimum quarterly distribution to its common unit for the first three quarters of 2009, which must be paid before Hiland Partners can make distributions to the subordinated units held by the General partner. General partner owned 3,060,000 subordinated units, which will not receive any cash distribution until the distribution arrearage to Hiland Partners common units is paid.

And operator, this concludes our formal remarks, and we’ll now open the line for questions.

Question-and-Answer Session

Operator

Thank you very much. (Operator Instructions). Your first question comes from the line of David Fleischer with Chickasaw Capital Management. Please proceed.

David Fleischer - Chickasaw Capital Management

You certainly gave us the details Joe and out of the difficult commodity markets earlier this year that said it is impressive that you’ve had a 24% gain in NGL volumes and also 10% gain in gas lines this year, given the economic environment that you have pointed to. You have also made it through a very difficult year, where all these commodity prices have been very weak and impressively you’ve not violated your debt covenants even as of September 30 so this is a better outcome than at several other or more than several other gathering and processing companies I would say.

Now we are seeing commodity prices moving up and moving up more than modestly accrued on the forward curve for next year trade in excess of $80 NGLs are now at $1 rising. And then the forward market one can lock in right now its in very decent margins which is what actually many are doing it really appears that you are on the verge other commodity sense of coverage your are on the verge of some excellent results in future periods, one could argue about that but that but that would be what I would propose and you indicate in your 8-K that you have discussions going with lenders just as others have renegotiated terms of their loan agreements my question for you now all this said is why isn’t there a very real course of action for you why can’t a deal that you said was not available to you back in the spring given where you were then why isn’t the deal available to be worked out with the banks just as a number of other companies would problems equal to or greater than yours have worked them out? I would also suggest that you say you don’t have a good access to capital you talk about the need for capital possible needs for capital, I would suggest that the sale of ones are right to existing shareholders who believe in your future would be a good way to bolster capital and allow existing unit holders who have suffered so much to benefit from the rebound in the markets that appears very much underway. So, I’d just love to hear your comments about why going to the banks and working the deal when they see the future when you [lot] in good numbers isn’t a very good and perhaps best path of action for existing unit holders?

Joe Griffin

You bet Dave let me address part of the some of the fundamental questions and the overall tone of the banks. And then I’ll let Matt also dig in to the capital markets and the bank situations. Good question, its something that all unit holders need to thoroughly understand, as we move forward between now and December 4. And I think you covered all the areas. David, with regards to volume and I did mention, we’d have some comments on that later in the discussion. I want to focus on some exit rates for you. So that we can start to see or at least on what is very important for people to understand the impact of drilling activity or [lack] thereof right now specially in the mid continent. From where I sit today if you look in the first quarter of ’09, our margin exit rate was 273,456 Mcf per day. Our third quarter exit rate in September was 252,701 Mcf per day, and if you pro forma that to get rid of the North Dakota Bakken commissioning, so you can do kind of an apples-to-apples basis compared to 2008. That volume was 247,000 a day, that’s a decrease of almost $26 million a day or 9.4%. And unfortunately as we look forward, even into October and I am working off estimates, we have our field people and our sales people watching and monitoring this very closely, but as we end the month of October. It looks like that our October rate is going to be 242,863 Mcf per day.

That’s a decrease from the March exit rate of almost 31,000 Mcf per day or 12%. And if you extract the North Dakota Bakken system out of that, which is about five, we are estimating about 5,000 Mcf per days during October, that’s been a bright spot for us. If you extract North Dakota Bakken system you are at 238,000 Mcf per day for October, compared to March, the March number of 273,000. that’s a decrease of 35,000 almost 36,000 Mcf per day or 13% from the first quarter. And a sequential decrease from September to October is also startling. So, we are very concerned about the activity right now and our mid [continent] systems as people should realize with the exception of the Woodford Shale system, which is the only unconventional gas play that we are in.

The rest of our systems are primarily deep vertical plays, those gas plays have slowed down significantly during 2009, and we just need to be very [conscious] about the volume drivers. Dave, I agree with you on all of your comments regarding the momentum of prices, no doubt about that. We have seen a rent in crude oil since I look at the beginning of the third quarter of this year. Looks like crude is up about 20%, NGL prices have increased about 43% and basis has tightened. But it’s also very important for people to understand where people’s facilities are? And kind of what the outlook is for drilling activity. As I look ahead also on the fourth quarter for this year excluding the North Dakota Bakken system, I am estimating right now, that we will connect two wells company wide. And that compares to 24 in the fourth quarter of ’08, that’s down 22 wells or 92%.

And so, I am extremely concerned about the throughput on the Mid-Continent systems and as we talked about in the earnings call, we are thrilled with the improvement that we’ve seen in crude oil prices and NGL prices and the impact that that’s had on the frac spreads, even as we look into the fourth quarter, the frac spreads are marking the market right now higher than what we saw in the third quarter. And if you look at the forward curve the frac spreads come off a little bit in calendar ’10 and ’11, as compared to the fourth quarter, but it is positive, that is a positive trend. And when I look at drilling activity, I am just trying to put into perspective what’s been going on in the Mid-Continent as we look forward. And I think that is something that’s pretty interesting to look at, if you look at the history of gas wells and wells we’ve connected in the Mid-Continent, and I go back to calendar ’06 on this, and try to look at the trends to get an idea of what our outlook would be. In 2006, in the Mid-Continent we connected 80 wells total company wide, and that was with natural gas index prices for the year averaging $6 in Western Oklahoma, and $6.15 in the Eastern Oklahoma and to break it down a bit further we connected 57 wells in Western Oklahoma, we connected 23 wells in Eastern Oklahoma. If you fast forward the tape to 2008, in 2008 which was the best year for indices that we’ve had in the Mid-Continent, I think since indices have been tracked on an average annual basis.

We connected 79 wells of the statistics that’s little bit startling when you look for this is out of those 79 wells only 18 were connected in Western Oklahoma and that compares to 52 wells in calendar '07 and 57 wells in calendar ''06. So we are starting to see a slowdown in the deep vertical plays. And I think this is attributable to the success that companies are having in unconventional gas plays and unfortunately we are not in the Marcellus we are not in the Haynesville and we do not have a large inventory of wells that are waiting on completion that can be connected as soon as prices turn around. Something people need to be concerned about.

In Eastern Oklahoma and the Woodford Shale which is our only unconventional gas shale play. In calendar '07, we connected 16 wells and the center point index out there was about $6.08. Calendar '08 which again was the best average annual indices of that region. I have been targeting it since '92. We connected to 37 wells.

In calendar '09, we connected one well and when I look at the drill schedule on the acreage that CLR has with us and they are our sole customer. Even thought they are going to be running a couple of wells both in the Anadarko Woodford and the Arkoma Woodford they have one well on our acreage scheduled for 2010.

And then when I look at the forward curves right now. Calendar '10 the index of the Western Oklahoma is going to be $5.14 mark-to-market as of day with a basis close as of October 30, in with the tightening. We don't give back to that $6 level right now until calendar '11. And so when I look at that I am very concerned about the drilling activity as we move in for the next couple of years ahead in the mid-continent.

On trail with the updates that we should see in North Dakota Bakken and I hope that we will resume some level of activity in Monata Bakken. I absolutely expect to do that. But we have got to keep in mind that those are casing head wells not gas wells and they come on at much smaller rates.

With regards to David in the credit facilities and you have seen what we have put in our press report and I am going to add a little bit of color to that. We continue to work with our lenders to see if we can come up with a solution. And today within our lender group, we have not had any success. In fact not only have we had any success, nobody in the group tight now is even willing to provide any hedging services for us either. And so that continues to be a very tough environment for us and I think some of the other midstream companies who don’t have that investment grade rating.

And then with that I think I will turn it over to Matt to add some more color on the banking side.

Matt Harrison

Yeah I will add some color to the hedging situation as well, we certainly are seeing the same strips that you are seeing David and I would give you a date and time, was it October 23. Joe we've looked at them hard, we looked at the strips hard. And we were looking at hedging hard but as you peel it back, to do 60% of our volumes and 2010 at the time to buy and put would have cost $7 million plus so $7 to $8 million to buy and put.

Now what that does is basically a lower EBITDA next year that upper strip by $7 million to $8 million and increase that’s a whole other thing. The other piece was if we sensitize our swap contract and I will remember Joe just mentioned we can not find a counter party currently that will give us a credit line, whether its inside the bank or outside the bank. We will get people to trade outside the bank but they were not providing credit lines. If we were to block the prices back at October 23 strip that I am referring to. We would have a potential, and prices would have gone to where they went in the third quarter of 2008. We would have a margin call of almost $35 million to $37 million, one that we couldn’t handle with the market cap of our size and credit facility where we are. So, we look at it hard but we just didn’t feel, we do feel like the risks are a way to reward to debt time.

I will give a little bit of color on the credit facility. I am very pleased of how we have managed the credit facility as a company up to this point. As we had mentioned, we are yet to pay a fee, an increased interest, everything else and I feel in our credit facilities it’s an asset to us right now to be quite frank with you. And what we have done here and you can kind of go through your proxies as well. We have had estimated equity holds as the year started a $80 million increase to $94 million. As you will see when you get our updated proxy, that’s been whittled down to $12.5 million as of requirements as of self [drilling] in 2009.

So, I am very pleased of how we have managed that facility. And again I have done some analysis of all the credit facilities in place, they put in place reason and whether it be Crosstex, whether it be Atlas, whether it be a [Southcross] deal; all of the different types of deals. And if you look at amendment fees, Libor floors, increased spreads those are just dollar number, percentage changes.

For the life of the facility if we were to recut a deal, it would cost us between $11 and $20 million of extra bank expenses between January 1, 2010 and May 2011. Other kind of more subjective restrictions related distributions excess cash flow suites and then just a general overall debt to EBITDA covenants that allow. We are seeing a lot of 3.5 times there as opposed to four times which again would require us to trace more equity.

So yes, we are looking at it and one of the solutions between now and 12/31/2010 are to do an amendment with the bank at $12.5 million financing hole, the way I look at it right now is I prefer to finance that, whether it'd be common units, subordinated units, something of that nature.

Joe Griffin

I would respond to you just with this one comment that the early part of the conversation was looking back at a tough year and now your comments are looking at, challenges, the world doesn’t change overnight as we look forward either and Joe you did point out the current challenge with gas prices and most observers of the industry you could argue about this, looking at this current big surplus of gases is the may be it’s a one year phenomenon and you can argue the other way but it could be longer but we are coming out of a whole in a lot of ways in price and volume.

And so I guess what I hear from you is really the need for capital and the time. And it seems to me that time, we are looking at a one year probably plus or minus one year time period of markets recovering, coming back we’ve seen a lot of that on the price side, its going to take higher prices for a while for your volumes to come back, for drillers to come back and drill more. And so it is a window and I guess I would hope and think that will allow these lenders or other lenders might be willing to work with you again.

And lastly, I would come back to the fact that you probably have a lot of investors who have suffered with you on the downside he would be very happy to put up money in the form of warrants or other securities, rights that would let them put up the capital and benefit from the upside be a little patient with time and come back and so I think that’s what you are seeing with some of the unwillingness of investors to go for this deal. So those are my comments.

Matt Harrison

Dave as always your comments are good and your questions are good and we appreciate you tuning in today. Thank you very much.

Operator

(Operator Instructions) Your next question comes from the line of Eric Conklin with Harvest MLP Funds.

Eric Conklin - Harvest MLP Funds

Just wondering what exactly is the game plan if the merger is rejected. Will you just then look forward and essentially issue equity?

Joe Griffin

Hi Eric, Joe Griffin I know you are busy with Matt and Derek on a number of occasions its real simple, public or private either one. We have to raise the equity to be in compliance with our leverage ratio covenant and with the credit facility of 12/31/09. And we are going to examine these alternatives for the with an eye towards minimizing user whole dilution and creating maximum liquidity for the partnership whether public or private.

Eric Conklin - Harvest MLP Funds

But there aren’t really any leverage you can pull as the deal doesn’t go through again you are looking at public or private some type of equity assurance?

Joe Griffin

Like I have mentioned I consider our bank agreement and asset right now and so I would look to do anything I could that wouldn’t trigger banks involvement and really the only way to do that is through equity.

Operator

(Operator Instructions) We are currently showing no more audio questions in queue at this time.

Joe Griffin

I appreciate it I would like to thank everybody for dialing in today to listen to the call and participating in the Q&A your thoughts your questions are very appreciative and we certainly respect that you all are taking the time to understand all the situations and the conditions as we move towards December 4, vote. I want to reiterate that your vote is extremely important. We should have our proxy supplement on file with the SEC very shortly. We have always respected your investment in the company and again your vote is very important. So with that I hope that everybody has a great weekend and a great upcoming holiday season and thanksgiving and Christmas. And we will look forward to reporting to you soon. Have a great day.

Operator

Thank you for your participation in today's conference. This concludes our presentation you may now disconnect have a good day.

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