Atlas Pipeline Holdings LP Q2 2008 Earnings Call Transcript

| About: Atlas Energy (ATLS)

Atlas Pipeline Holdings LP (AHD) Q2 2008 Earnings Call August 1, 2008 9:00 AM ET


Brian Begley - VP of IR

Ed Cohen - Chairman and CEO

Bob Firth - President and CEO of Atlas Pipeline Mid-Continent, LLC

Mike Staines - President and COO

Matt Jones - CFO


Sharon Lui - Wachovia

Carlos Rodriguez - Hartford Investment Management

Eric Kalamaras - Wachovia

Yves Siegel - Aroya Capital

Helen Weir - Lehman Brothers


Good day, ladies and gentlemen. And welcome to the Quarter Two 2008 Atlas Pipeline Partners Earnings Conference Call. My name is Nora and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference. (Operator Instructions)

I would now like to turn the presentation over to your host for today's call, Mr. Brian Begley, Vice President, Investor Relations. Please proceed.

Brian Begley

Good morning, everyone, and thank you for joining today's call. Before we begin our discussion on our second quarter results, I would like to remind everyone that when used in this conference call the words believes, anticipates, expects, and similar expressions are intended to identify forward-looking statements. These statements are subject to certain risks and uncertainties which could cause actual results to differ materially from those projected in the forward-looking statements. We discuss these risks in our Quarterly Report on Form 10-Q and our Annual Report also on Form 10-K particularly in Item One.

I would also like to caution you not to place undue reliance on these forward-looking statements which reflect management's analysis only as of the date hereof. The Company undertakes no obligations to publicly release the results of any revisions to forward-looking statements which may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

Now I would like to turn the call over to our Chairman and Chief Executive Officer, Ed Cohen. Ed?

Ed Cohen

Hi. Hello, everyone. Listen, APL's 2008 second quarter saw a number of signal accomplishments. Even in a challenging economic environment, we've stuck successfully I might say to our fundamental businesses. We have totally rejected the kinds of marketing activities that sometimes exaggerate profits but at high risk. And we have carefully maintained a strong financial position and we continue to cultivate carefully calibrated risk control policies and operations. And Bob Firth will speak about these risk control policies and operations in detail a little bit later.

I'm going to report now on the quarter itself. First of all, in a period when credit and equity markets have been frozen for virtually all companies, and quite cold even for energy businesses, we were able to raise in late June over $0.5 billion in additional long-term debt and equity financing.

We sold over 7 million shares of new commercial stock generating net proceeds of over $260 million. Partnership likewise issued $250 million of the 10-year 8.75% senior unsecured notes. And we obtained a further $80 million of increased bank commitments for our senior secured revolving credit facility increasing the amount committed under that facility to $380 million.

At June 30, 2008, only $20 million of this revolver was in use leaving $360 million for the company's ongoing and future needs. In an era when cash seems to be king, we should be part of royalty. I'm pleased to salute the skill with which our financial officers headed by Matt Jones have handled the challenging and extraordinarily volatile environment.

We've actually been navigating, as you know, in hurricane force commodity and credit wins which have damaged and even sunk some other energy companies. And I think we are all familiar with this in recent newspaper headlines. So we are very glad that we were able to get ahead of the wave, get cash in a difficult period and I think we stand strong right now. Our operations have been going very well. APL's Northern and Central Oklahoma processing plants have been operating at full capacity through the second quarter and have been forced to bypass a continual excess of gathered natural gas.

Fortunately, however, our new Sweetwater II expansion became operational at the end of the second quarter increasing our total Elk City/Sweetwater processing capability to 310 million cubic feet per day from only $250 million previously. That's very, very important for us because since gathered gas volume in the second quarter was already almost 293 million cubic feet per day well beyond our prior processing capabilities at Elk City/Sweetwater, this increased capability promises increased profitability in future quarters especially as we are now able to process at the new Sweetwater II the excess gas gathered at our Waynoka and Chaney Dell complex. That's what we call our Western Oklahoma division.

During the second quarter 2008, Waynoka/Chaney Dell was forced to bypass about 17 million cubic feet per day because processing capacity there too was fully utilized even after the reopening in the first quarter of the previously idled Chaney Dell plant. Now because of the earlier completion of the new connector pipeline between these two facilities, a portion of this Western Oklahoma excess is already flowing to the expanded Sweetwater facility.

I should note that despite capacity constraints even during the second quarter because of innovative operational approaches, our West Oklahoma system that's Waynoka and Chaney Dell, still was able to increase NGL production by 8% over the prior quarter. And our new Nine Mile processing plant is scheduled to enter service at yearend 2008, a plant that will be positioned about equidistant between Waynoka/Chaney Dell and Elk City/Sweetwater.

With this additional 120 million cubic feet per day of processing capacity, revenue and profits should increase still further. And early reports still provisional suggest that distributable cash flow through our company in July 2008 was the best per unit in our company's history. Onward and upward as the prophet said. All of our divisions continue to prosper and expand. Appalachia is showing remarkable growth, an increase of 28% in gas throughput in the second quarter of 2008 as against the prior year period. Gas transmitted on the Ozark system averaged 402 million cubic feet per day, an increase of 25% from 322 million cubic feet per day in the second quarter of 2007. Processed volumes in West Texas increased by 5% over the prior quarter.

Even our smallest processing operation, Velma, a perennial laggard, showed an increase of 1 million cubic feet per day in processed volumes as compared to the year earlier period. But we do expect Velma to show increases similar to our other divisions once we complete construction of the 70 miles of 16-inch high pressure supply pipeline between the Velma gas plant and Madill, Oklahoma. This project currently underway will enable Velma to access the burgeoning Ardmore Shale play and should vastly improve revenues and margins at Velma. And Bob Firth will have a lot more to report shortly about this development.

But I should say, of course, at least a few words about our actual second quarter results. In a few words, they were great. But they must be understood in context. Adjusted EBITDA reached $76 million compared with $24.2 million for the prior year's second quarter, an increase of $51.8 million or over 214% over the corresponding 2007 period. Distributable cash flow was $55.9 million, an increase of $39.2 million or almost 235% over the prior year's second quarter.

Partnership declared a record quarterly cash distribution for the second quarter of 2008 of $0.96 per common limited partner unit. This distribution represents an increase of $0.09 per unit or 10.3% compared to the prior year's second quarter.

Our general partner, Atlas Pipeline Holdings, likewise, declared a record quarterly cash distribution for the second quarter 2008 of $0.51 per common limited partner unit. Finally, system-wide volumes of 1.3 billion cubic feet per day for the second quarter 2008 compared to volumes of only about 800 million cubic feet per day for the prior year's second quarter, an increase of approximately 63%.

But these results should be understood in the light of two important factors which I want to emphasize. As a result of the blockbuster Anadarko acquisition in July of 2007, APL was a much larger company in 2008 than it had been in 2007 so we recognize that these increases in gross numbers are fully understandable and don't necessarily represent anything fantastic.

But we still manage to grow distributions per unit and I believe that the true level of our operating success in the second quarter of 2008 has been substantially understated as a result of financing arrangements bearing no inherent relationship to our actual operations. And that augers well for future quarters including this present third quarter during which those financing arrangements have largely come to an end.

During the second quarter 2008, certain proxy hedges put into effect in connection with the Partnership's acquisition of the Chaney Dell and Midkiff/Benedum systems from Anadarko in July 2007, these proxy hedges became less effective as a result of significant increases in the price of crude oil and less significant increases in the price of ethane and propane.

These hedges cost us approximately $33 million in cash flow during the second quarter of 2008, but we've now paid off about 85% of these contracts. As a result, the Partnership's future cash flow should more accurately reflect the revenues generated from its ethane and propane volumes produced in its natural gas processing operations.

As we've announced previously, this change should result in substantial increases in distributable cash flow and in distributions themselves. Specifically, as previously indicated also, we anticipate distributions of $2.00 to $2.20 per unit for the second half of 2008. And these distributions will be paid after a 1.3 times distribution coverage ratio.

The midpoint of this guidance range represents a 14% increase compared to cash distributions paid in the second half of 2007 and those distributions, the 2007 distributions, were after only a 1.2 times distribution coverage ratio. In addition, we've affirmed full year 2009 guidance of $4.25 to $4.50 of distributions per common unit again after a 1.3 times distribution coverage ratio.

Now to share more information on past achievements and future expectations in our Mid-Continent region and on our hedging policies, I'm passing the presentation to a Bob Firth. Bob?

Bob Firth

Thanks, Ed. The successful efforts by our respective Mid-Continent systems has yielded the following physical results. Across all five of our Mid-Continent systems for the second quarter of 2008, we moved approximately 1.2 bcf a day, produced 51,600 barrels a day of NGLs, and produced approximately 3,000 barrels a day of condensate. And on our well connect program, we connected approximately 150 wells to our systems.

At our West OK system, we averaged 284.5 million a day in the second quarter which is 11% increase over volumes gathered in the first quarter of 2008. Additionally, we recorded NGL production of 13,358 barrels a day which is approximately an 8% increase over the prior quarter. We continue to see strong growth in this region where we had 89 wells connected to our system during the second quarter.

As remarked in the first-quarter conference call, we restarted the idle Chaney Dell gas processing plant which provided an additional 20 million a day of processing capacity and has helped reduce bypass volumes on the West OK system. Despite this new capacity, however, the system once again began bypassing an average of 17 million a day throughout the second quarter. However, we are pleased to announce that in June we began transporting gas on our slider pipeline which connects West OK with our Elk City system.

Since becoming operational, we have transported an average of 8 million a day of bypass gas to our highly efficient Sweetwater plant for processing. We expect these transported volumes to increase as producers at West OK strengthen their drilling programs and as processing capacity is made available with the startup of our 60 million a day Sweetwater II expansion.

On the West Texas system, we had a daily volume of 150 million a day which was approximately a 5% increase over the prior quarter. Likewise, NGL production was also up slightly in the second quarter which where we reproduced 20,830 barrels a day. We were successful in the second quarter at connecting 41 wells to the West Texas business unit and we continued to a aggressively pursue our 150 million a day consolidator cryo plant which will be operational in June of 2009. The construction of this plant will increase NGL recoveries and also provide us an additional 40 million a day of incremental processing capacity to take advantage of the drilling program of our partner Pioneer.

At Elk City/Sweetwater system, we moved volumes of approximately 292.5 million a day. And we produced about 10,452 barrels a day during the quarter. This was an increase of about 720 barrels a day over second quarter of 2007, which represents about a 7% increase. From a supply perspective, we connected 15 wells to the quarter.

Although throughput volumes, and well connects were not at the pace that we wanted for the second quarter, we are confident because of our initiatives that we've undertaken to increase the connects, and also the volumes, that the volumes will increase over the next several quarters. Remember, we were limited by the processing capacity at Sweetwater 1; now we have Sweetwater II online, therefore, we can connect additional packages of gas that we have in the pipeline.

On the Ozark gas transmission system, we average 402 million a day which is up sequentially from the first quarter average of 390 million. For comparison purposes, the average day to volume was 322 million a day, in the second quarter of 2007. So, we continue to see very strong demand in the third quarter to move volumes on Ozark, at our certificated capacity of 400 million a day.

At Velma, as Ed mentioned, we processed about 65.5 million a day for the second quarter. This was a notable 5% increase over the 62 million a day for the first quarter. NGL production was a solid 6,993 barrels a day which was approximately a 5% increase over the prior quarter. From a commercial standpoint, we connected nine wells to this system and we see a tremendous amount of drilling behind this system in the Ardmore Shale.

Let me quickly discuss our projects, our ongoing growth projects. We are pleased to announce that we started up at the 60 million a day Sweetwater II expansion, which will increase our processing capacity 120 to 180 million a day at Sweetwater. This expansion will also increase the overall Elk City/Sweetwater system to a capacity of 310 million a day and allows us to process the increased volumes behind the system that are projected to come online in the next several quarters.

Additionally, the completion of the 16-inch pipeline connecting Sweetwater to WestOK allows for the ability to process volume that would otherwise be bypassed due to processing capacity constraints at WestOK.

The construction of our 9 Mile plant is ongoing and we expect an in-service date of December 2008. This plant will be located on the newly constructed pipeline between the Elk City and the WestOK systems. The 9 Mile plant will provide an additional 120 million a day of processing capacity and will result in the aggregate processing capacity in Western Oklahoma of approximately 680 million a day to our Elk City, Sweetwater, 9 Mile, Waynoka, Chester and Chaney Dell plants. The completion of the 9 Mile plant will complete our Western Oklahoma processing hub which will provide us operational flexibility and redundancy between WestOK and Elk City/Sweetwater systems.

We continue to aggressively pursue efficiency opportunities on our West Texas system. As previously mentioned, our construction of our 150 million a day consolidator cryo plant which will be operational in June of 2009. The construction of this plant will increase NGL recoveries of our current stream, and will also provide an additional 40 million a day of incremental processing capacity on this system, bringing the total processing capacity to 190 million a day.

At our Velma system, we have begun construction of a 70-mile, 16-inch high-pressure supply pipeline between the Velma gas plant and Madill Oklahoma and also the installation of four compressor stations along the line that will provide low-pressure services to our producer. This pipeline will access the Ardmore Basin of the Woodford Shale formation primarily in Carter and Marshall Counties. The producers are very receptive of the opportunity to have access to the deep ethane recoveries available at the Velma gas plant, which will maximize the value of their 5 to 6 gallon gas.

The project has an expected completion date of March 2009, although we expect to begin gathering a portion of the volume as the pipeline is extended eastward. The construction of this pipeline will further benefit the Velma gas gathering system by lowering operating pressures resulting in the increase in processed volumes from the existing system. We anticipate that this initial phase will become part of a larger project in the future to potentially build a new facility near Bennington, Oklahoma that can provide us with incremental processing capacity.

With the increased drilling and demand in the Fayetteville Shale areas, Ozark is moving forward with the Standing Rock compression project which will increase our capacity form 400 million to 500 million a day. Our anticipated in service for this project will be October 2008. We continue to evaluate various opportunities to extend the Ozark system across the Mississippi River to interconnects with other interstate pipes with access to premium markets. As we continue to move forward and develop these projects, we will keep everybody apprised.

In summary, we are delighted with the solid growth of our existing systems and confident of the success that our organic growth projects have begun to realize. We are continually evaluating other growth initiatives that cannot be divulged at this time, but I look forward to sharing the investment community as they near implementation.

Next, let me address our hedging approach. Let me begin by reiterating that in the Mid-Continent, we firmly believe in hedging our commodity exposure at our various facilities. We understand that hedging is complicated and our hedging function is structurally very conservative by design. We view this function as a way to mitigate our risk versus viewing it as a profit center.

For example, we have a hedge committee that approves all of our trading activity before any trades are executed. Our trades are executed by our Director of Risk Management who obtains approval of all hedges through our hedge committee. Naturally all of our hedging confirmations are sent to a party other than the person doing the trades providing appropriate segregation of duties. Finally, all of our hedges are over-the-counter, always with member banks in our credit facility.

We address our hedging by focusing on the following. One, we look at gas quantity, and what the drilling activities are going to be currently and in the future. Two, gas quality. We continue to evaluate on a daily basis the BTU and the GPM content of the gas we are connecting and for future connects. Three, we look at our contract mix, the mix between percent of proceeds, make whole, fee, POL and POG. Fourth, we look at plant and pipeline as well as the downstream curtailments or any downtime that we might have for maintenance. And five, is our ethane rejection economics which we monitor on a daily basis. These issues along with the usual backwardation of the commodity curve result in our hedge strategy including hedging more in the prompt periods versus the future periods.

Let me summarize our current hedge positions. They are as follows. For the next 18 months, we are approximately 50% hedged on our long NGL and condensate exposure. For the calendar year 2010, we are approximately 65% to 70% hedged on our NGL and condensate exposure. This is higher than our target since we have not unwound the crude cost related to ethane and propane in the first half of 2010. For the calendar year 2011 and 2012, we are approximately 10 to 15% hedged on our long NGL and condensate exposure.

One final point I want to discuss is ethane. While ethane makes up approximately 50% of our overall NGL stream, it is only approximately 18% of our overall NGL gross margin. We obviously mitigate this risk through the hedging strategies mentioned previously, but we also have physical opportunities to mitigate any deterioration in ethane price or increase in the natural gas price. At all of our plants, we are able to warm up the tower, effectively reducing the amount of ethane recovered in the NGL stream. This yields more natural gas that we can sell at the tailgate of our plant as residue gas.

In conclusion, we are currently very close to our targeted minimum commodity hedge positions for the next several quarters. We continue on a daily basis to evaluate elongating our book through a layered approach.

That concludes my remarks today and I'll turn the call over to Mike Staines.

Mike Staines

Great. Thanks, Bob. I'll talk about Appalachian operations which continued to show remarkable growth. Gas throughput during the second quarter of 2008 averaged a record 84.5 million cubic feet per day, an increase of 28% over the similar period of 2007. Field estimates of gas throughput for the month of July 2008 averaged 87.9 million cubic feet a day, with some days well in excess of 90 million cubic feet per day.

Much of this fantastic growth is coming as a result of our affiliate Atlas Energy Resources' Marcellus activities. And I won't go into any detail on that, but I'll just let you know next week Atlas Energy does have a call, and I'm sure they will go into great detail at that time.

During the second quarter of 2008, we added 203 total wells to our system, compared to 146 wells added during the second quarter of 2007. A total of 69 Marcellus wells have been drilled and connected to our system, with eight additional wells waiting to be completed and connected. Approximately 240 traditional shallow formation wells are in the process of being connected. Importantly, Atlas Energy has identified over 3,900 conventional shallow drilling sites adjacent to our gathering system, which does not include many thousand potential Marcellus locations.

As those of you who also follow Atlas Energy will know, we are in an unusual position compared to our peer group in that we already have in place an extensive gas-gathering infrastructure serving the heart of the most active region of the Marcellus formation. This system has been constructed over the past several years to gather production from the traditional wells in the basin, and recently expanded to accommodate the growing volumes from this Marcellus activity.

Currently, we have approximately 50 million cubic feet per day of additional throughput capacity in southwestern Pennsylvania, where this Marcellus activity is focused, with experienced initial productivity from vertical Marcellus wells as high as approximately 3 million cubic feet per day, and probably substantially greater from future horizontal wells. Consequently, we have an aggressive game plan to add a further 125 million cubic feet per day of capacity by the middle of 2009.

As I mentioned last quarter, Atlas Pipeline has now expanded into Tennessee, where Atlas Energy has been an active driller and the largest operator in Tennessee for almost four years. We acquired the Volunteer gas gathering system and related facilities for $9.1 million in February 2008, and have committed to construct the 20 million cubic feet per day Big Mountain gas processing facility with startup projected by March 2009.

This facility will serve production from an area of several hundred thousand acres controlled by Atlas Energy and other producers. Recently there have been some very impressive wells drilled and tested targeting the Chattanooga Shale, Monteagle, Fort Payne, and other formations in this area. And we are of course in the process of expanding this system to serve those producers.

More recently we have entered into an agreement with the Citizens Gas Utility District of Scott and Morgan Counties, Tennessee, to exclusively provide gas processing services for all gas using the Citizens intrastate transmission system to reach a market on the Spectra East Tennessee system, with startup of that 20 million a day plant projected for March 2009. Our plan is to eventually connect the Volunteer system to the Citizens system, which will give us effective gathering and processing control over an area of approximately one million acres.

In Pennsylvania, our Irishtown gathering and processing system in McKean County continues to run well ahead of original expectations and in line with more recent budgets, now on track to generate an IRR of more than 30%. This improved performance is the result of modifications to the plant that result in greater liquid recovery, and of course an improved price environment for the natural gas liquid components, of which we retain an average of 50%.

That concludes my remarks. And with that, I'll turn the call over to Matt Jones.

Matt Jones

Thanks Mike. To repeat, our Partnership generated approximately $56 million of distributable cash flow in the quarter representing a 6% increase compared to the first quarter of this year. To arrive at distributable cash flow for the quarter, we made certain adjustments to EBITDA to reflect non-recurring charges related to the termination of crude oil derivative contracts. These are the proxy hedges that Ed had addressed and the correlation impact of the terminated proxy contracts.

We also made adjustments to reflect non-cash derivative expense and non-cash stock compensation expense. I'll briefly highlight each of these adjustments and then move to our income statement to summarize the impact to our operating results of these items and generally discuss operating results for the quarter.

During the quarter, we terminated 85% of the crude oil derivatives contracts that were entered into as a hedge against movements in ethane and propane prices for production periods ending in the fourth quarter of 2009. We unwound these positions because of the long-standing correlation between natural gas liquids prices, particularly ethane and propane and crude oil prices changed as increases in the forward strip pricing of crude oil has not been matched by proportional increases in natural gas liquid prices, although increases in natural gas liquid prices have been substantial.

This market dynamic and the uncertainty associated with future correlations partially concealed the operating success of our processing assets and made it more challenging to evaluate our Partnership's future cash generating ability. With the successful completion of the termination of these contracts, we recently affirmed our previously announced anticipated increase in distributable cash flow per unit guidance after 1.3 coverage of $2.00 to $2.20 per unit for the second half of 2008.

The midpoint of the range represents a 14% increase compared to the second half of 2007 with a 50% increase in coverage from 1.2 to 1.3 times. We also affirm 2009 guidance of $4.25 to $4.50 of distributions per unit after 1.3 coverage. The removal of the hedged charges associated with the terminated crude positions and the resulting elimination of the correlation issue for these hedges should allow the Partnership to realize meaningfully higher levels of cash flow beginning in the third quarter of this year based on current market conditions.

To give you a sense for the magnitude of this, if we were to remove from our second quarter results the negative impact of carrying the equivalent amount of ethane and propane related crude hedges that we terminated later in the quarter and in July, we would have reported adjusted EBITDA for the quarter closer to 95 million to $100 million compared to $76 million.

For the third quarter and beyond, we also anticipate growth in our business from the addition of the Sweetwater II plant. The expansion of throughput capacity on the NOARK systems scheduled for completion late in the third quarter; the addition of the Nine Mile plant in the fourth quarter of this year; the extension of the Velma system to reach growing production in the Ardmore Shale scheduled for completion in March of 2009 and the construction of the Midkiff consolidator plant scheduled for completion in June of 2009. We also anticipate continued throughput growth in our Appalachian region because of factors that Mike just addressed.

Moving back to our second quarter adjustments, as a result of the crude oil hedged terminations during the quarter, we recorded a non-recurring termination charge of $116 million. This amount is included in the other income or loss category in the revenue section of our income statement.

We also adjust EBITDA this quarter to reflect the impact of the decline in correlation experienced during the quarter on the terminated positions totaling roughly $11 million. Next we adjust EBITDA to reflect non-cash derivative expenses of $181 million. As we have mentioned in the past, certain of our hedges qualify for effective hedge accounting treatment and others do not. Those that do not are mark-to-market at the end of each quarter and any change in valuation from the previous quarter end is run through the income statement.

The mark-to-market charges relate to estimates for future periods and our non-cash so we add this amount back to our cash flow for the quarter. This non-cash expense is also included in the other income or loss category on our income statement. Other hedged positions that settle during the quarter have a cash impact on our business and are therefore not added back to EBITDA or cash flow. After adjusting EBITDA to reflect derivatives activity during the quarter, we subtract from adjusted EBITDA a cash interest expense, preferred unit dividends and maintenance CapEx.

Briefly, our cash interest expense totaled $17.5 million for the quarter. This represents a decline of about $2.2 million compared to the first quarter of this year. This resulted from a decline in LIBOR rates this quarter compared to last quarter.

With the completion of the $250 million senior unsecured note offering this quarter and the addition of a two year LIBOR swap contract entered into during the quarter for a notional amount of $250 million, roughly 78% of our interest rate exposure based on the quarter end outstanding debt amounts is fixed through the second quarter of 2010. Roughly 43% is fixed through 2015.

Our maintenance CapEx for the quarter came in at approximately $2 million. We expect maintenance expenditures to trend higher through the remainder of the year and as we continue to expand our capital asset base, we expect maintenance CapEx in 2009 to run about $20 million to $22 million for the year. Of course, quarter-to-quarter volatility will likely continue based on the timing and magnitude of capital projects.

Moving to our operating results, the gross margin generated from natural gas and liquid sales total $89 million which was nearly equivalent to the gross margin generated in the first quarter. Our gross margin per processed unit came in at roughly $1.43 per unit, which is consistent with margins that we've generated in recent quarters. Increases in natural gas liquids prices which favorably impact our key poll margins were offset by very substantial increases in natural gas prices which adversely impact our keep whole margins were offset by very substantial increases in natural gas prices, which adversely impact our key poll margin.

Also the correlation decline between natural gas liquids prices and crude oil prices negatively influenced our margin in the second quarter. Of course, higher natural gas prices and natural gas liquid prices positively impact our percent of proceeds contracts and are likely to influence continued investment in well drilling efforts by the natural gas production companies who use our services.

In general, movement of natural gas liquids prices, natural gas prices and crude oil prices and the co-variability and correlation of these products will together influence our absolute gross margin and cash flows generated from this segment of our business. The termination of the crude oil derivatives positions recently completed will greatly reduce the influence of correlation in future periods and will allow us to more fully realize cash flows generated from our production of the ethane and propane components of our natural gas liquid streams.

For our transportation and compression fees which are generated largely by our NOARK and Appalachia systems and to a lesser extent the Elk City and Chaney Dell systems. We generated approximately $20 million of gross profit this quarter compared to approximately $14 million in the second quarter of last year, a 40% increase. We continue to experience significant growth on these systems which remain well positioned to transport natural gas in some of the fastest growing natural gas basins in our country including the Fayetteville Shale and Ardmore Shale regions of the Mid-Continent and the Marcellus Shale region of Appalachia.

Plant operating expenses this quarter totaled $0.24 per processed unit, consistent with the first quarter of this year. Compared to the second quarter of last year, unit cost increased by $0.07 per unit. As we have said in the recent past, unit cost increases compared to last year are primarily a function of higher operating costs of the Midkiff/Benedum and Chaney Dell plants compared with the processing plants that were part of our system in the first half of last year. Of course, the processing margins generated by the Midkiff and Cheney plants are generally greater than those generated by our other plants.

Higher absolute costs over the last couple of quarters have been offset by higher levels of processed units. After adjusting for non-cash compensation expense, general and administrative expenses this quarter totaled approximately $8.8 million compared to roughly $5 million in the second quarter of last year. The increase is associated primarily with the acquisitions of Chaney Dell and Midkiff/Benedum systems in the third quarter of last year which greatly expanded the size and scope of our business.

As for our capital position at the end of the quarter, we had roughly $1.1 billion of Partner's capital, a $707 million term loan outstanding that matures in July of 2014, a $380 million revolving credit facility with about $20 million drawn at the end of the quarter which matures in July of 2013, $295 million of senior unsecured notes maturing in 2015, and the newly issued $250 million of senior unsecured notes due in 2018. The '018 notes were issued during the quarter and we used proceeds from the offering to reduce the outstanding balance of our term loan and reduce the outstanding amount drawn against our credit facility.

The completion of the offering allowed us to expand the duration of our debt and create a significant available liquidity under our revolver. Also during the quarter, our syndicate of banks increased our committed revolving credit facility to $380 million leaving $360 million of liquidity under this facility available to us at the end of the quarter. We also completed common unit offerings during the quarter totaling 7.1 million common units. We use the proceeds to fund the termination of the crude derivative collars that we've discussed that we believe create the opportunity to significantly increase our cash flow generation on a per unit and absolute basis.

Expansion CapEx in the quarter totaled $71 million, significantly weighted towards the projects that Ed, Bob and Mike discussed, including the completion of the funding of the Sweetwater II plant and related gathering systems the NOARC standing rock compressor station, and various extensions and expansions to our other systems.

I'd also like to update our expansion CapEx estimates for the remainder of this year and 2009, primarily to include CapEx associated with the development and construction of the Velma processing plant pipeline connection and related compression extending to Madill, Oklahoma and the Ardmore Shale related production.

For the remainder of this year, we expect expansion CapEx to approximate $170 million to $280 million. For 2009, we currently estimate growth capital expenditures to approximate $135 million to $140 million. In total then for the next six quarters through the end of 2009, we scheduled roughly $300 million to $300 million in expansion CapEx projects. Our company remains well positioned to benefit from the growth in drilling activity in the regions where we operate and we'll continue to aggressively pursue opportunities associated with the development of those regions.

Moving quickly to Atlas Pipeline Holdings, Atlas Holdings declared $0.51 distribution for the second quarter, a substantial increase over the second quarter of last year. During the quarter, Atlas Holdings acquired an additional 278,000 common units of Atlas Pipeline Partners, increasing its holdings of Atlas Pipeline common units to approximately 5.8 million units. Atlas Holdings also owns 100% of the incentive distribution rights and 100% of the general partner interest in Atlas Pipeline Partners. These interests will allow Atlas Pipeline Holdings to continue to directly benefit from the future anticipated success of Atlas Pipeline Partners.

That concludes my remarks and I'll turn the call to our Chief Executive, Ed Cohen.

Ed Cohen

And I on my part will advise the operator that we are ready for questions.

Question-and-Answer Section


(Operator Instructions). And your first question comes from the line of Sharon Lui of Wachovia. Please proceed.

Sharon Lui - Wachovia

Hi. Good morning, guys.

Ed Cohen

Good morning.

Sharon Lui - Wachovia

I was wondering if you could just touch on the commodity price and the NGL ratio assumptions in setting your '09 guidance? What's your long-term outlook and the type of cushion that you are looking at if there is a correction in commodity prices?

Ed Cohen

Matt, do you want to address that?

Matt Jones

Sure. Sharon, for modeling purposes, we assumed NGL prices that were somewhat below those prevailing in the marketplace today. I think Bob had said about 50% of our NGL volumes through '09 are effectively hedged through existing positions, so about 50% of our current volumes will flow with commodity price movement.

As far as the correlation is concerned, we assumed for guidance purposes that correlation would remain historically low. In fact, we assumed correlations would remain about where they are or have been on average over the last, say, four to six weeks. So, we are certainly hopeful that correlations will recover. I expect that they will, but conservatively in our modeling we assumed correlations would continue at the, again, historically low levels that prevail today.

Sharon Lui - Wachovia

Okay. So I guess on the crude oil and the natural gas side, are you assuming, I guess the current strip prices?

Matt Jones

We are, we are.

Sharon Lui - Wachovia

Can you also talk about the rationale of eliminating the crude oil puts that were purchased for the outer years?

Matt Jones

Could you repeat the question, Sharon?

Sharon Lui - Wachovia

I noticed in your updated hedges that the crude oil puts that were purchased in the outer years, 2010 to '12, were taken out. I was just wondering what's the rationale for …

Matt Jones

We unwound or removed or terminated the puts that were in place associated with the positions that were entered into, primarily in connection with the Chaney Dell, Midkiff/Benedum acquisitions. The puts that were put in place were 60 to $70 puts. We didn't feel that those puts really provided much protection to us any longer.

So we are, as you know, continuing to take a view of the '010, '011 and even '012 hedges. We're watching the market closely and we are determining the appropriate course of action associated with those positions. But as far as the puts that we had in place are concerned, we didn't feel that the puts provided us really any meaningful protection going forward, so we simply terminated those along with the other positions that we have unwound recently.

Sharon Lui - Wachovia

Okay. Thank you.

Matt Jones


Ed Cohen

Thank you, Sharon. Next?


Thank you. Your next question comes from the line of Carlos Rodriguez from Hartford Investment Management. Please proceed.

Carlos Rodriguez - Hartford Investment Management

Thank you. Congratulations on your results.

Ed Cohen

Thank you.

Carlos Rodriguez - Hartford Investment Management

I had a question, if you could just quickly talk a little bit about your volumes generically. At what price does natural gas need to get to before we start seeing lower drilling activity and hence well connects?

Ed Cohen

People in the E&P business I think are generally of the view that at 7 to $8 you begin to see decreased enthusiasm. At 13 to $14, we see resistance on the part of consumers so that I think the general view is that ideal pricing in the present context might be at about 10 to $11, which incidentally is pretty much where pricing is right now.

But I would like to emphasize that there is a long lag time. The idea that you can cut off the drilling or commence drilling is really illusory. So that when prices rose sharply in the 2001 period, there was very little additional drilling because people weren't yet convinced that prices would stay up at those rates. It really wasn't until two years later, 2003 or maybe even into 2004, that increases really picked up, and we think the same thing would happen on the downside if prices were to fall back to the $6 or $5 level.

And don't forget, there was a period in the last three years when prices were as low as $4 an Mcf with, very little effect on drilling. But if prices fell to those very low levels, there probably would be a very substantial time lag once again until drilling began to fall. People would have to be convinced that this was a continuing or semipermanent situation, and financing and activities already underway would have to work their way through the system before you would see some substantial fall.

Carlos Rodriguez - Hartford Investment Management

That's helpful. And one other question. Everyone is aware of what happened at SemGroup, and there's a lot of concern being focused on any other companies that have hedging activities about sort of rogue trading activities. I know you touched upon it a little bit already on the call, but can you give us some further assurances that that could not happen at Atlas?

Ed Cohen

Carlos, that's a very good point, and of course you were very much aware of the fact that we added the section dealing with trading activity and so on to really address that point. But I would correct one thing that you said, which is that this grew out of hedging activity. The kind of trouble that one saw at SemGroup, and that one has seen in other areas such as the situation with the SocGen bank in France, relates to trading activity.

The one thing which our company has always absolutely eschewed is trading activity. That's a way in which you can make additional profits, and we've been criticized in the past for being a stick in the mud and for not seeing this as a possible source of profitability. In fact, the absence of a trading division in our company is something which is not by accident, but again something that people thought that perhaps if we were more go-go-ish and more alert to profit opportunity, we might pursue.

The reason we've never pursued it, the reason we why we've always ousted it from any company that we have been involved in if we make an acquisition where there is a trading component, is exactly what the risk is. We prefer relatively low risk, together with the profit aspects that result. Namely, if you have low risk you have to make money the old-fashioned way. So we don't have the trading component at all. As far as a guarantee that that particular problem could not occur, I think we can come as close as possible to making that guarantee. Since we don't carry on these activities, since we don't have any traders, we don't have any possibility we think of rogue trading.

Now having said that, one should bear in mind that the energy business, and probably all businesses, are inherently not capable of being free from risk, so that we are constantly monitoring, as Bob has indicated, in every which way exactly how we conduct our hedging activities.

And I should add as to how we conduct other activities. We have numerous risk-control devices and we spend our time, a good portion of our time, trying to think of ways in which we can further enhance safety. Most of the time, you get very little credit for it. In the present situation, as I think Bob has made clear, we think we're probably entitled to some credit because our old-fashioned non-aggressive non-go-go approaches seem to be somewhat vindicated.

Carlos Rodriguez - Hartford Investment Management

Thank you very much. That's helpful.

Ed Cohen



And your next question comes from the line of Eric Kalamaras of Atlas Point Partners. Please proceed.

Eric Kalamaras - Wachovia

Hi, this is Eric Kalamaras, obviously from Wachovia.

Matt Jones

Good morning, Eric.

Eric Kalamaras - Wachovia

Hi guys. Quick question. I guess if I could try to drill down a little bit on Chaney Dell, would you be in any position to give some sort of expectation on processing volumes as an exit rate for '08 relative to where you exited second quarter?

Matt Jones

You know, Eric, we don't give specific volume guidance for our systems, and we don't give general or aggregate guidance for volumes that we generate as a company. I think that we continue to expand that system. I know Bob addressed that. So, and you asked specifically about Chaney Dell, didn't you?

Eric Kalamaras - Wachovia

I did.

Matt Jones

Yeah. Our expectation certainly is that with the increased capacity of our systems, the drilling activity that's taking place in and around our systems, the relationships we have with the key producers around that system, that it will continue to grow and expand our operation there. But Bob may like to address this question as well. But we simply don't give specific volumetric guidance on individual systems or in the aggregate for our business.

Eric Kalamaras - Wachovia

Understood. Let me try something slightly different. Bob, can you indicate on the Nine Mile plant what the expectation is for, you said it's at 120 million capacity, but in December, what do you think that looks like in terms of a kind of a testing or a ramp up? What do you expect initially off of that?

Bob Firth

Well, I think in the first quarter, Eric, well, we're always bringing a new plant on line so the volumes are going to vary somewhat. But our anticipation is to have somewhere between 60 and 80 million a day in that plant first quarter. And we'll go from there. It is 120 million a day. We do anticipate that Chaney Dell system continue to increase volumes. We do anticipate loading up the Nine Mile plant from the south and the north. So we will have a combination of spillover from the Chaney Dell system going into Nine Mile and also gas going into the Nine Mile plant from the south.

One thing on the Sweetwater facility, we just signed a producer, a 90 section dedication behind Sweetwater. This is one of the larger more active producers which we think will be very beneficial to that system and filling up those plants and keeping those plants at capacity. We've also working on another deal for 30 million a day package with another company to go into that system. So that just gives you an idea of some of the things we're working on. But we anticipate 60 to 80 million in the first quarter for that facility.

Eric Kalamaras - Wachovia

Okay. Great. Thanks for that perspective. I noticed on the Elk City/Sweetwater, it's hard for me to determine where this lies, but I noticed that the processed and the gathered volumes are down slightly from first quarter. Is there some sort of a pressure issue there, something transpired to cause that?

Bob Firth

Well, there is a couple of things, Eric. Keep in mind, we were making all of our tie-ins for Sweetwater II. So we probably lost 10 to 15 days of barrels of production because we're making tie-ins. It's always a good news, bad news. Good news is now we have additional capacity. The bad news was we lost some of our production for 10 to 15 days behind there.

We also held off a couple of packages of gas until the third quarter to tie them in because we just didn't have capacity and we didn't want to bypass and pay for processing. So that's the reason we saw the dip in the barrels and the volume for the second quarter. That's a good question.

Eric Kalamaras - Wachovia

Okay. Thanks. And then on the Sweetwater on the fee portion, do you expect any changes there on the gas that's gathered that will be going into Sweetwater II?

Bob Firth

Well, we Eric, on all these systems keep in mind we have fee business driving before the processing. They're just not a straight processing type agreements.

Eric Kalamaras - Wachovia


Bob Firth

And so we always have fee business. We continue to see the fee business portion of Elk City increase because we're adding more services and more compression behind the system. The volumes coming into Sweetwater, the new volumes are more heavily weighted to percent of proceeds. But we still have some make-haul portion of that on the new volumes coming in. So that's kind of where we see from a volume standpoint is we're driving the fee business and then we have the processing side that layers on top of that.

Eric Kalamaras - Wachovia

Sure. And Bob, is it fair to say that the general margin makeup between the portion that the fee and the margin that you get from the percent of proceeds, and even part of the keep-whole, even though it's kind of small, but I guess what I am asking is do you expect the relationship of gross margin as a percent of those types of contracts to change much? I wouldn't think that it would, but…

Bob Firth

No we don't. A good example, and Ed alluded to this and as well as Matt, is that gas prices have slid back some and the ethane price has slid back some, but it's also rebounded this month. So when you look at it from a margin standpoint on the unhedged portion of that, we're actually as good or better off than we were before, because gas prices have slid back. And so when that happens, your processing spread is still there.

Eric Kalamaras - Wachovia

Sure, sure. Okay.

Bob Firth

So we continue to see those margins, as you mentioned, to be equivalent what they have been.

Eric Kalamaras - Wachovia

Okay, great. All right guys I appreciate it. Thanks much.

Bob Firth

Thank you, Eric. Next?


And your next question comes from the line of Yves Siegel of Aroya Capital. Please proceed.

Yves Siegel - Aroya Capital

Well, thank you and good morning.

Bob Firth

Good morning, Yves

Yves Siegel - Aroya Capital

Could you just follow-up on Eric's question? How do you see the breakup between keep-whole, percentage-of-proceeds, and fee-based business, and if you look forward a year how do you think that mix is going to look? And then maybe put that into context with looking out a year. How do you think the business is going to look between fee-based, i.e. pipeline transportation type of gross margin, versus the commodity exposure? Easy questions I know.

Ed Cohen

Matt, do you want to take a shot at that?

Matt Jones

Sure. Yves, I think you know that our Elk City/Sweetwater plant and Chaney Dell plant, the majority of the contracts associated with those plants are keep-whole contracts. We have at Elk City/Sweetwater and at Chaney Dell, or WestOk as we call it, probably today 25 to 30% of our contracting on those plants is POP contracting. As Bob had said, we have importantly a fee-based element associated with all the molecules that we transport and process on those system. So these are blended systems, but the proportionality of the contracts really today at WestOk, and Elk City/Sweetwater, are heavily weighted towards keep-whole.

I'll allow Bob to address what's likely to progress over the next year or so. But at our Midkiff/Benedum and Velma plants, the preponderance if not the totality of the contracting on those plants is POP. So, that's the mix currently. Bob might like to address what our expectations are for contracting moving forward, but that's where we are today.

Bob Firth

Hi, Yves. Let me reiterate the systems, because I think sometimes we get hung up on our keep-whole type systems. Keep in mind, Ozark is totally fee business, Velma is percent-of-proceeds business, West Texas is totally percent of proceeds. So, you have the Western Oklahoma systems, fee business driving, the processing layered on top.

And the way we view with our hedging and our fee business, for instance, ethane is 50% of the volume of our processing, but it's only 18% of the revenue stream, and we're 50% hedged of that volume. So you only have 9% of your ethane that is currently unhedged. We mitigate that risk by physically operating the plants. And we like having a small portion of this unhedged because then we don't have the problem when one of the prices, either gas or liquids, gets way out of whack with the market.

For instance, if gas goes to $20, we can warm up the plants, cover our hedge position, turn the rest of it to gas, and make as much or more margin than we're currently making today. So that's how we mitigate that risk. We've got, between fee business and what we've got hedged on the processing side, we feel real comfortable that we've mitigated any type of our risk from a product standpoint down to the 10% level.

Yves Siegel - Aroya Capital

Got it. Thank you. And if I could just follow-up with perhaps two other questions. One is can you give us an update on Pioneer, what they are doing? And perhaps put that into context as well with how important is that to help finance the growth based on the current capital budgets?

Ed Cohen

Pioneer has announced in public presentations that their intention is to exercise their option, which is exercisable in two portions, partly this year and partly next year. They have until November to do the exercise, and we haven't heard anything from them but they haven't made any public announcement to suggest that they would not go forward as they have announced.

The financing is not critical, whether they exercise or don't exercise, because we have, as I indicated earlier, placed ourselves in an extremely strong financial position. If cash is king, we certainly have the cash; we can always use additional cash, so that if they do go forward with the exercise we would certainly accept the money.

Yves Siegel - Aroya Capital

I guess I was thinking in terms of financing growth via equity and debt, how do you think about that, and how Pioneer it might fit into that equation?

Ed Cohen


Matt Jones

I think, Yves, that as far as the mix of financing is concerned going forward, we'll continue to finance the business as we have in the past. I think what we have done historically would be a good guide for you as to the nature of the financing of the business going forward.

That is to say that to the extent that we put debt on the company, we would like to extend the duration of that debt as much as possible to, again, to the extent we have debt on the business, we like to remove as much as possible, prudently, the interest rate movement risk associated with that debt. As far as the equity component is concerned, we'll finance growth projects generally from internally generated cash and by utilizing availability under our revolver; generally we will take out those relatively temporary borrowings with long-term borrowings and we'll equitize or layer in term debt to take out those positions.

With the Pioneer position, we will use proceeds. If Pioneer exercises, we'll use proceeds to pay down or reduce our debt, more than likely. And fortunately, as we've said, we have very substantial opportunities to continue to invest in our existing systems, which brings really great returns to us relative to our capital. So yeah, as Ed said, we have good flexibility today. I think our financing pattern will follow the pattern that we've undertaken in the past, and that's where we are.

Yves Siegel - Aroya Capital

Okay. And my last question relates really two-parter. One is, Matt, if you could just reiterate again if you have to post any margin as it relates to your derivative contracts? And the last question is given your really very enviable growth position, how do you think about consolidation opportunities going forward given your growth expectations and also given your pretty good financial situation right now as well?

Ed Cohen

This is Ed. Matt, I think I will address the second point and then we can go back to the first point.

Matt Jones


Ed Cohen

All right. We think we are in a very strong position and we're glad to see people coming to recognize it. Others seem not to be in as strong a financial position. We have been hearing from factors in the industry suggesting consolidation is before us and I think if consolidation does take place within the industry, we're likely to be a major beneficiary because of our relatively strong financial position. Matt, you might want to go to the first point.

Matt Jones

Sure. I think Bob had mentioned that we hedge only through members of our bank group. So those that hedge with us are secured by our assets. We had one smaller bank relationship recently that requested that we make a cash deposit with them as we unwind our exposure with them so we've done that. But we remain in good shape with our hedge relationships and certainly we have significant capacity to add to those positions which is to do so.

One other thing I might mention in this regard is that you'll see when we file our 10-Q, and we do this routinely with each of our filings, quarterly filings, you'll see that we had a hedge liability at the end of the quarter of about $500 million. With the decline in crude oil prices recently, that hedge liability today if we were to run the calculation today to determine the hedge liability, that liability would be closer to $300 million. So the liability itself has come down by roughly 40% since the end of the quarter.

Yves Siegel - Aroya Capital

Thank you, gentlemen.

Ed Cohen

Okay. Next?


And your next question comes from the line of Helen Weir of Lehman Brothers.

Helen Weir - Lehman Brothers

Yes, hi, good morning. I just had a quick question about the status of the Tenark pipeline project, how the negotiation with the shippers are going? If you could just give any updates there?

Bob Firth

This is Bob. We continue to negotiate with our shippers on the Tenark project. We held our open season. We continue to talk to them. We've also submitted another request for transportation to Southwestern. They're wanting additional capacity and they're anticipating another large commitment. So we've also made a bid to them for a pipeline as well as the Tenark. So we're continuing to negotiate with several parties.

We also naturally will be offering transportation as soon as the Standing Rock compressor comes on because FERC requirements we'll open that up for people to take that transportation and we've had a number waiting in line for a while. We continue to work on a couple of smaller projects within the system that producers are wanting that will be additive to Ozark in the future. So that's kind of an overall summary working on a number of different projects there.

Helen Weir - Lehman Brothers

All right. Great. Thank you.


You have no further questions at this time.

Ed Cohen

All right, we thank everyone for their participation. And as you can hear, we are optimistic about the future and I hope that we will have as a result some really good things to report at conference call in about three months. Thank you all. Bye.


Ladies and gentlemen, thank you for your participation in today's call. This concludes the presentation. You may now disconnect. Good day.

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