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On 8-21 I updated the DCFs and changed out one brokerage - and this resulted in some significant changes in the consensus DCF estimates. And the consensus estimates then resulted in changes in my adjusted CAGRs. And the combination of changed DCFs and changed CAGRs resulted in some major changes in the Forecaster predictions. DPM [which I purchased last month mostly based on its great metrics] is an example - falling from 17% under-valued based on the CAGRs and DCFs I had yesterday to only 5% under-valued today when the consensus 2008 DCF estimate fell from $3.42 to $3.11 and I lowered the adjusted CAGR from 11 to 10. EROC went from 5% over-valued to 15% under-valued based on the DCF changes when its 2008 DCF estimate rose from $1.52 to $2.05. So this is a reminder [and for me an unpleasant reminder] that DCFs estimates are volatile. The CAGRs changed like crazy - so on 8-31 I changed from reporting Yahoo and MSN estimates to reporting current Yahoo and last month Yahoo estimates - to show the volatility. The CAGRs, EPSs, ratings and target prices are NOT yet updated to the month end numbers for the E&Ps and GPs - expect those to be done by Monday. The spreadsheet below uses month ending data. The 'monthly price change' column is for unit price changes, while the 'year to date' stats is for total return. This explains the jumps in year to date gains in the distribution heavy months of February, May, August and November without similar gains in those month's unit prices. CEF numbers are for MLP and MLP-hybrid Closed-End Funds. The 'Ten Year Yield' numbers are for the US Treasury. Tracking the spread of the average MLP's yield to the Treasury has been a useful tool for timing of MLP purchases - buy MLPs when the spread is high. The CEF spread is used in academia to measure investor sentiment. Buy MLPs when the price is at the largest discount to NAV.
SGLP IPOs in July / Reports Earnings in August Various On 7-18 Tulsa, Oklahoma energy partnership Semgroup Energy Partners LP priced 14.38 million shares at $22 a share in a bid to raise $275 million. SemGroup Energy Partners owns and operates terminalling and storage facilities with approximately 6.7 million barrels of storage capacity, including approximately 4.8 million barrels of storage capacity located at the Cushing Interchange, two pipeline systems consisting of approximately 1,150 miles of pipeline, and tanker trucks used to gather oil at remote wellhead locations generally not covered by pipeline and gathering systems. On 8-15 SGLP reported net losses of $12.2 million and $24.5 million, respectively, for the three and six months ended June 30, 2007. These financial results reflect the historical results of the Partnership's predecessor. EBITDA was $11.7 million and $23.3 million, respectively, for the three and six months ended June 30, 2007. As-adjusted cash available for distribution was $9.2 million and $18.1 million for the three and six months ended June 30, 2007, respectively. On 8-27 Citi analyst John Tysseland started coverage of SemGroup Energy Partners LP with a "Hold" rating Monday, saying its share price already reflects the company's assets and growth potential. Tysseland called its location the "primary gateway" between the Gulf Coast and Midwest refining centers. He estimates its distribution will grow by 15.2% through 2011, more than twice the average forecast for master limited partnerships. A.G. Edwards & Sons analyst Ronald Londe initiated SemGroup's rating at "Buy" on 8-24 with a $33 price target, implying 11% upside to current price. Londe based his rating on the company's assets, growth outlook, yield and management team. SemGroup has "opportunities for expansion of current assets and likely acquisition of assets from its general partner," Londe wrote in a note to clients. TCLP Reports Net Income/Unit of $0.45 vs. $0.47 in Q2-06 PRNewswire 8-02 TC PipeLines reported Q2-07 net income of $17.7 million [$0.45/unit] compared to $9.0 million [$0.47/unit] for Q2-06. The increase in net income is primarily due to the positive impact of the Partnership's acquisitions which included a 46.45 per cent general partner interest in Great Lakes Gas Transmission Limited Partnership (Great Lakes) on February 22, 2007, and a 49% general partner interest in Tuscarora Gas Transmission acquired on December 19, 2006. Partially offsetting these positive contributions to earnings were increased financial charges on higher outstanding debt balances and lower earnings from Northern Border Pipeline and Tuscarora. WPZ Reports Net Income of $0.56 vs. $0.25 in Q2-06 PRNewswire 8-02 Williams Partners announced Q2-07 net income of $26.2 million [$0.56/unit] compared with $34.8 million [$0.25/unit] in Q2-06. Distributable cash flow for limited-partner unitholders totaled $28.3 million for Q2-07, compared with $6.1 million for Q2-06. Distributable cash flow per unit was 72 cents in Q2-07, compared with 41 cents for Q2-06. The increase in distributable cash flow for the quarter is due to strong operational results, lower operating costs, as well as a special cash distribution from Discovery due to hurricane-related insurance receivables. GEL Reports Net Income Loss of $0.09 vs. Gain of $0.24 in Q2-06 PRNewswire 8-02 Genesis Energyreported a net loss of $1.4 million [$0.09/unit] for Q2-07. Expense related to our stock appreciation rights plan for the quarter of $3.7 million, resulting predominately from the 63% increase in our common unit price during Q2-07, was the primary reason for this loss. Without this charge, net income would have been $2.3 million [$0.17/unit] for the quarter. This compares to net income in the 2006 second quarter period of $3.4 million, or $0.24 per unit. For the second quarter of 2007, Available Cash before reserves was $3.9 million, or $0.27 per unit, which was more than adequate to cover distributions to the common unitholders and general partner for the quarter totaling $3.2 million or $0.23 per unit. APL Reports Net Income Loss of $2.20 vs. Gain of $0.41 in Q2-06 Market Wire 8-03 Atlas Pipeline Partners reported EBITDA of $24.2 million for Q2-07 compared with $22.8 million for Q2-06. The quarter-over-quarter results were favorably impacted by higher system-wide volumes of approximately 759.4 MMcfd compared with 644.1 MMcfd for Q2-06, an increase of approximately 18%. Increased throughput volume on the NOARK interstate pipeline system, the addition of the Sweetwater processing facility and an increase in Appalachia gathered natural gas contributed to the aggregate growth in system volumes. On a GAAP basis, APL recognized a net loss of $20.8 million for Q2-07, largely related to $28.5 million of non-cash derivative expense. The non-cash expense was due to the impact of commodity price movement on hedge instruments entered into in conjunction with the recent acquisition of Anadarko Petroleum's interest in certain gathering and processing assets. APL established distribution guidance at a range of $3.80 to $4.00 per common limited partner unit for 2008, while also increasing the targeted distribution coverage ratio to 1.2x. KSP Reports Net Income of $0.37 vs. $0.30 in Q2-06 Business Wire 8-03 For Q2-07 KSP reported Net income pf $3.8 million [$0.37/unit] compared to $3.1 million [$0.30/unit] for Q2-06. KSP's operating income was $7.8 million, an increase of $1.1 million, or 16%, compared to $6.7 million of operating income for Q2-06. This year-over-year increase resulted from the continuing expansion of KSP's fleet barrel-carrying capacity, including the addition of four new tank barges since the beginning of Q2-06. These results were also positively affected by continued strong rates and solid vessel utilization, partially offset by increases of $1.5 million in depreciation and amortization due to the expanded fleet, and $0.5 million in general and administrative expenses in support of KSP's growth. Average daily rates in Q2-06 was $10,615 compared to $9,699 in Q2-06. Net utilization in Q2-06 was 82% compared to 80% in Q2-06. EBITDA increased by $2.6 million, or 18%, to $17.0 million for Q2-07 compared to $14.4 million for Q2-06. PAA Reports Net Income of $0.78 vs. $0.81 in Q2-06 Business Wire 8-03 Plains All American reported Q2-07 net income of $104.8 million [$0.78/unit] compared to $80.3 million [$0.81/unit] in Q2-06. EBITDA for Q2-07 of $210.2 million, an increase of 76% compared $119.6 million for Q2-06. Excluding selected items impacting comparability, segment profit from Transportation operations in Q2-07 was $89.4 million, 58% higher than Q2-06 segment results of $56.5 million. Transportation volumes for Q2-07 were 2.9 million barrels per day versus 2.1 million barrels per day in Q2-06. Adjusted segment profit for Facilities operations was $31.8 million representing a 249% increase over $9.1 million for Q2-06, reflecting increased storage capacity and throughput activity due to the Pacific acquisition and the completion of new capital projects. Marketing operations adjusted segment profit of $92.9 million represents an increase of 49% over Q2-06 results of $62.5 million reflecting an expanded asset base and favorable market conditions. PAA Conference Call Notes: During 2005-2007 there were favorable contango markets [one could sell oil at higher prices for future delivery - a condition that helps the storeage business]. Contango spread have lessened, but PAA projects this will not change the profit outlook by much. Ross Paine with Wachovia asked how much of PAA's total storeage is leased to third parties. PAA: That varies by location - and the number is dynamic. Currently it is 55% to 60% of storeage. Ross: Will the demand for storeage now be less with smaller contango - and how will that deficted be made up? PAA: Our past profits due to contango were never part of our base line numbers. And there is a second factor, those customers who lease from us do so operationally - and not for prior contango trades - so our customers will not go away. Our storeage lease business has long term contracts. Ross: What is the average life of those storeage contracts? PAA: That number would not give a correct impreesion given that some are short term, but they have been rolled for years. Ross: Do you have a debt to EBITDA target? PAA: Back when our earnings were less fee based, we have a target of 3.5x and less. Today, now that we have more fee based reveneues, are targets are higher: 3.5x to 3.8x. We currently are at 3.3x. The shrinking ratio is not our goal. We believe that a 3.8x target is consistent with our current BBB+ credit ratings. Sam Arnold with Credit Suisse asked if the strong Q2 marketing performance was enhanced by some market arbitrage opportunities like the conditions at Cushing [where there were lower prices] vs St James [storeage for imports where hub prices were hgiher]. PAA There were a couple of markets where you could get arbitrage. At St James the cap line was at a high level. But the crude and refined markets are not that fungible. It is not easy to move resources from on location to another and pocket the profits - it is not like natural gas. It is easier to create profits on computer screnes than in reality. John Edwards with Morgan Keegan asked for the maintenance cap ex projection for 2007. PAA: At begining of the year is was estimated at $45 million - now we estimate $52 million. A good run rate is $40 million to $60 million, unless we aqcuire more assets. To some extint, the maintenance cap ex is weather dependant - and rains slowed down the expenditures in the first half of 2007 - so we plan to catch up on some projects in the second half. UCLP Reports EPU of $0.17 PRNewswire 8-07 Universal Compression Partners reported revenue of $18.8 million and net income of $2.3 million for Q2-07, compared to revenue of $17.6 million and net income of $2.3 million in Q1-07. EBITDA totaled $10.4 million in Q2-07 compared to $9.5 million in Q1-07. Distributable cash flow totaled $6.9 million in Q2-07 compared to $6.0 million in Q1-07. The distributable cash flow generated in Q2 is approximately 1.2 times the amount of the cash distribution to unitholders [compared to 1.33x in Q1-07]. Total Debt to Capitalization was 61.8% and Total Debt to Annualized EBITDA coverage was 2.9x. Universal Compression Partners commenced operations in October 2006 upon the contribution of certain contract compression assets in the United States from Universal Compression Holdings in connection with the initial public offering of Universal Compression Partners. CPNO Reports Net Income of $0.31 vs. $0.51 in Q2-06 PRNewswire 8-07 Copano [ko-puh-no] Energy reported revenue for Q2-07 increased 34% to $281.7 million compared with $209.6 million for Q2-06. Net income decreased by 30% to $13.3 million [$0.31/unit] for Q2-07 compared to $18.9 million [$0.51/unit] in Q2-06. CPNO's reported results were held back by increased non-cash hedging amortization totaling $5.2 million for the quarter and the write-off of approximately $2.7 million of charges and expenses incurred in connection with a potential acquisition that was not consummated including additional non-cash charges for associated hedges of approximately $1.8 million. Gross margin for Copano's operating segments, excluding the Corporate segment, increased 10% compared to Q2-06. Total segment gross margin decreased 4% to $46.4 million in Q2-07 from $48.2 million in Q2-06. EBITDA for Q2-07 were $29.5 million [$34.8 million before charges] compared with $34.3 million for Q2-06. Distributable cash flow for Q2-07 (prior to any retained cash reserves) totaled $25.0 million, representing 133% coverage of the increased distribution. CPNO Conference Call: CPNO had $3.1 million in maintenance cap ex in Q2-07 and $4.5 for first half of 2007 with a $9 million to $11 million run rate per annum. There was a $1.4 million decrease in interest charges - less borrowed from revolver. There was a 6.9% average rate on debt and CPNO has a 2.8x debt to EBITDA ratio. New this year is a $175 million tax reserve for the Texas margin tax. CPNO continues to see opportunites for acquisition. CPNO beleives they still have access to capital from their bank and institutional investors. CPNO also stated that gas wells have come on line faster than anticipated in Q2-07 in OK and tri-county area of North Texas. John Edwards with Morgan Keegan wanted more color on the hedge amortization charge - and wanted to know if if will fluxuate in the future. CPNO: That number should be predictable - it is money that went out the door in December [when the hedge was made]. That cash is gone. It is the cash coming in that varies. A second analyst asked: If the $5.2 million of cash went out door long ago - why was ot not added back to DCF? CPNO: We thought it was appropriate not to - but there are analyist who think we should. When our outflow of cash spent on hedges was smaller, it was not really a focus in our calls. Hedging is a non-cash event - but it is ongoing. It is like an insurance cost. Analyst: You are buying options? CPNO: Yes - we buy once or twice a year. Analyst So why not expenses then when you buy them? CPNO: That is not proper - they are assets - they have a life that goes for over five years. We will continue to maintain hedges. But there is a headwind going forward [as CPNO grows, their amount of hedging grows]. The other charge was in failed acquisition costs - and those cost will continue, but probably the amount in Q2 was higher than the run rate. We suggest that you would be best served to look at the charges seperately from what the business did - the business generated more cash this quarter. John Edwards noted the realized margin on NGLs were lower than he had estimated. CPNO: That was what we were expecting. One large contract restructured to reduce margins in peak periods, but increases our cash flows in non-peak periods. Doing this resturcture took some risk off the table. Margins in July were in the 40s per gallon, in August they have been in the mid 50s range. John Edwards wanted to know what the outlook is for organic cap projects. CPNO: We will spend more than previously projected in the tri county property purcahsed from Cimmeron. CPNO projects that it will spend in mid to high 8 figures [annualized run rate] for next eight quarters John Edwards wanted color on expansion cap ex. CPNO said they project $50-$100 million annualized rate on cap expansion - but that depends on things like weather and the availablity of equipment. HLND Reports Net Income of $0.16 vs. $0.37 in Q2-06 PRNewswire 8-08 Hiland Partners, LP reported net income for Q2-07 of $2.5 million [$0.16/unit] compared to $3.8 million [$0.37/unit] for Q2-06. This decrease is primarily due to additional depreciation expense and interest expense incurred as a result of the acquisition of the Kinta Area gathering assets effective May 1, 2006 and interest expense related to borrowings for our organic growth projects, offset by increased sales volume from our Kinta Area, Bakken and Eagle Chief gathering systems. EBITDA for Q2-07 was $11.9 million compared to $10.8 million for Q2-06, an increase of 11%. Total segment margin for Q2-07 was $18.7 million compared to $15.9 million for Q2-06, an increase of 18%. MMLP Reports Net Income of $0.41 vs. $0.40 in Q2-06 PRNewswire 8-07 MMLP reported net income for Q2-07 of $5.9 million [$0.41/unit] compared to $5.2 million [$0.40/unit] in Q2-06. Revenues for Q2-07 were $162.3 million compared to $133.1 million for Q2-06. Second quarter 2007 net income was negatively impacted by a $0.3 million non-cash mark-to-market adjustment on derivatives. This non-cash adjustment resulted in a reduction to net income of approximately $0.02 per limited partner unit. MMLPs distributable cash flow for Q2-07 was $11.1 million [and divide that by 13,642,950 units to get 80.6 cents per unit compared to a upcomig distribution of 66 cents per unit]. MWE Reports Net Income of $0.17 vs. $0.51 in Q2-06 PRNewswire 8-08 MarkWest Energy Partners today reported net income of $8.3 million for Q2-07 compared to net income of $14.1 million for Q2-06. These results include $12.4 million of non-cash costs associated with the mark-to-market of derivative instruments and non-cash compensation expense. Excluding these non-cash items, net income for Q2-07 would have been $20.7 million. For Q2-07 DCF was $35.4 million [divided by 36.216 million units results in a DCF per unit of 97.74 cents compared to an upcoming distribution of 53 cents] compared to $29.7 million [divided by 25.876 million units results in a DCF per unit of $1.15] for Q2-06, an increase of 19% in gross dollar terms. The Q2-07 total distribution coverage ratio was 1.35, including the associated GP and IDR requirements. The MWE Conference Call: DCF for the first half of 2007 was $68 million up 37% from 2006. MarkWest continues to evaluate transaction between MWE and MWP. Especially around Carthage, contract structures are changing to less 'keep whole' contracts to more 'fee based' contracts giving MWE less commodity price exposure. MarkWest had an $8.4 million mark to market on derivative [different number than stated above]. MWE has rolling 36 month period hedges and is fully hedged through Q2 of 2010. Interest expenses were down $2 million. MWE had less debt due to equity offerings since Q2-06. MWE has a market cap of $1.3 billion now vs $1.1 billion at the end of Q2-06. MWE had $529 million in debt - and the debt to market cap ratio was 48%. MWE has a 2007 DCF forecast of $130-140 million. Distribution guidance: they project an increase of at least 10%. $285-290 million in expansion capital budgeted for 2007 [with $85 million spent in Q2] - $200 million of that is going to Woodford developments. Year to date there has been $62 million of cap expenditures spent on the Woodford system. 200 miles of pipe laid with extra compression added. This should allow MWE to gather new volumes with only the addition of well connects for added expenses going forward. Newfield over next 6-12 months will exploit more opportunities in Woodford. During Q2 MWE picked up two new producers in Woodford - 70 addition sections added by those two. So far MWE has 8 Woodford area companies contributing to MWE lines. In Western OK - a phosolate system was added in the Anadarko basin. A new processing plant should come on line in mid 2008 that will take processing capacity from 95 million to 155 million. Around Carthage the gas volumes continue to grow. Successful horizon drilling continues to expand. MWE believes that prospects look good for the whole Cotton Valley reservior. Around Applebee MWE continues to see companies having drilling success. The upgrades in 2006 to that system allow MWE to handle increased volumes. MWE's StarFish investment looks to add $7 million in cash flow in 2007. In Appalachia the projection of increased gas volumes will drive need to expand there. Michael Bloom with Wachovia wanted the maintenance cap ex budgets for 2007. MWE: It is $6 million. Bloom asked if MWE could give an estimate for the timing of an announcement with MWE. NO. Bloom asked what are the prospects for a second Javalina facility. MWE: Looking at adding a second facility. We have great relatinships with producers around that, and that is opening doors. Refiners like having that kind of processing done by an outside party. Such plants represent big dollar expenditures. We are having discussions with producers in that area. Ron Londe with AG Edwards noted that the volumes were off in some systems in the southwest. MWE: Those declines in volumes were spread over 17 gathering systems - and they were normal declines due to lack of drilling activity and due to the natural fall of in production from older wells. But keep those declines in perspective: Those systems contribute only $1 million to $1.5 million per year to MWE. Londe asked if MWE had announced who the new Woodford producers were? MWE: The formal announcements should come in a month or so. Mark Easterbrook with RBC asked about the volume capacity at Woodford. MWE: We are at 125 today, but we have just added compression to up that to 250 with the new compression. Laterals continue to be added. Newfield announced they will continue to drill - and they will now use 40 acres spacing - where it had been 80 acres spacing. Newfield had 1300 acres under lease originally and is now up to 1500 acres leased today. Easterbrook noted that since MWE had a high cap expenditure budget - when would they need new equity? MWE: It depends on how fast we spend - it could be 2 quarter from now In response to a question from Les Chamey with Zimmer Lucas, MWE noted that they the possibility of even more spending in Woodford, due to adding even more processing and more pipelines. MWE had internally forecasted that they would get more producers in Woodford, but they may have been even more successful than their forecasts. Chamey asked what amount might MWE spend on Appalachia projects. MWE: It appears the Equitable's project at Big Sandy is going forward - but they have their own gas for that [competing?] system. Chesapeake's drilling is adding more gas. We expect to expand fractionization and marketing. We could spend a little as $15 million and could be as high as $50 million in Appalchia. DPM Reports Net Income of $0.17 vs. $0.51 in Q2-06 PRNewswire 8-08 DCP Midstream Partners reported net income of $0.5 million [$0.01/unit] compared to $8.3 million [$0.47/unit] for Q2-06. The financial results for Q2-07 include $6.2 million of non-cash losses associated with the mark-to-market accounting treatment of commodity derivative instruments, as compared to non-cash losses of $0.4 million for Q2-06. EBITDA for Q2-07 was $8.8 million, compared to $12.5 million in Q2-06 period. Increases in margin attributable to the Lindsay system in southern Oklahoma were offset by non-cash mark-to-market derivative losses, higher operating and maintenance expense in the natural gas services segment, and higher general and administrative expense due to acquisition costs and increased labor and benefit costs. DPM's distributable cash flow for the six months ended June 30, 2007 was $25.8 million, or 1.2 times the amount required to cover its current distribution to the general and limited partners. For the six months ended June 30, 2006, distributable cash flow was $22.4 million. The mark-to-market of our derivative instruments is a non-cash item and does not affect distributable cash flow. Natural Gas Services gross margin decreased $1.3 million to $16.9 million while Propane gross margin was $3.8 million and NGLs gross margin was $1.0 million. The DPM Conference Call: DPM had $625 million of growth acquistions closed or announced in Q2. These included [1] a gathering and compression in southern Oklahoma [the Lindsay system] for $180 million purchased from Anadarko Petroleum; [2] a 25% interest in E. Texas G&P complex and 40% interest in Discovery Producer Services $270 million from DCP Midstream; and [3] G&P assets in Piceance Basin (Collbran joint venture) and Powder River Basin (Douglas system) $165 million from DCP Midstream. To fund these acquisitions DPM did a $130 million private placement in Q2 at $43.25/unit. DPM's credit facility was raised to $820 million. The $270 million east Texas acquisition with partialy funded with $28 million in new units going to DCP Midstream [the GP]. DPM's revenues are 40% fee based and 60% with commodity exposure - and of that 60% approx 80% is hedged. Jonh Tyseland of Citi asked how much more room exists on the credit facility? DPM: After acquisitions, our current debt on the facility was under $500 million - after the Momentum acquisition closed, debt was in the low $400 million range. But there are two parts to that: the Revolver at $600 million and a term loan at $250 million. We will use some of each one. The rates is determined by band and is based upon leverage - cost is 42.5 basis points over LIBOR. Tyseland asked if DPM will do any more equity funding this year? DPM: We would anticipate a Q4 offering. Rich Groph of Lehman asked for run down on drilling activity. Given that natural gas prices are down, he expected a cut back. DPM: N Louisiana continues to see solid drilling activity. Not up - but maintained at high pace. The east Texas rig activity is up 15%. In the mid continent [the Lindsey assets], Exco Resources palns to move rigs in based on our discussions. Anadarko had not been drilling. In the Rockies, we have not seen a cut back by producers. Good oil prices and liquid recoveries. TLP Reports Net Income of $0.17 vs. $0.51 in Q2-06 Business Wire / MarketWatch 8-09 TransMontaigne Partners L.P. reported that Q2-07 revenues increased to $20.9 million from $11.6 million in Q2-06 due principally to revenues generated by the Brownsville and River facilities. Net earnings were $1.46 million, down from $1.54 million in Q2-06. Net earnings allocable to limited partners were $1.43 million [15 cents/unit] down from $1.51 million [21 cents/unit] in Q2-06. Analysts polled by Thomson Financial were expecting, on average, a profit of 33 cents a unit. Adjusted operating surplus [a DCF substitute?] generated during the period was $4.4 million compared to cash distributions allocable to the period for those units outstanding during the period of $4.9 million. The shortfall in the adjusted operating surplus is due principally to accelerating amortization of deferred financing costs of approximately $0.8 million during the three months ended June 30, 2007, associated with the repayment of the $75 million term loan outstanding under the Senior Secured Credit Facility. RGNC Reports Loss Business Wire 8-14 Regency Energy Partners reported a net loss of $8 million for the three months ended June 30, 2007, compared to a net income of $4 million for the three months ended June 30, 2006. Second-quarter 2007 results included an increase in general and administrative expenses of $12 million (consisting primarily of a nonrecurring charge resulting from the vesting of all long-term incentive plan awards, upon the change of ownership of Regency's general partner), an increase in interest expense of $8 million, an increase in operation and maintenance expense of $3 million, and an increase in depreciation and amortization expense of $3 million. EBITDA increased 53% to $33 million for Q2-07, compared to $22 million for Q2-06. Comparing Q2-07 results to Q1-07 results, adjusted EBITDA increased by 24%. Revenue for Q2-07 increased 40% to $302 million, compared to $215 million for Q2-06. Adjusted total segment margin increased by 43% to $51 million in Q2-07, compared to $36 million in Q2-06. Regency generated $21 million in cash available for distribution, representing coverage of 1.35 times the amount required to cover distribution to common unitholders and 0.92 times the amount required to cover the distribution to the general partner and all limited partners, including subordinated unitholders. Universal Compression Partners Changes Name to Exterran Partners Business Wire 8-19 Universal Compression Partners, L.P. (UCLP) announced that it has changed its name to Exterran Partners, L.P. concurrent with the closing of the merger of Hanover Compressor Company (HC) and Universal Compression Holdings, Inc. into Exterran Holdings, Inc. (EXH). Effective 8-21-07, Exterran Partners' common units will trade on the NASDAQ under the symbol "EXLP." Petrohawk to Spin-off E&P MLP BusinessWire 6-25 Petrohawk Energy Corporation (NYSE:HK) announced plans to form a MLP with certain of its Permian and Arkoma Basin properties. Petrohawk expects its MLP, HK Energy Partners LP, initially to acquire interests in certain of the Company's long-lived oil and natural gas reserves located primarily in the Permian Basin. The MLP is expected to generate future growth principally through acquisitions, both from the parent company and from other sources. Petrohawk expects to file a registration statement with the U.S. Securities and Exchange Commission for the initial public offering of units of this MLP during the third quarter of 2007 and anticipates that the offering will be made during the fourth quarter of 2007. Approximately $150-225 million of these partnership units are expected to be offered to the public, subject to market conditions. Tetra Technologies to Spin-off MLP Houston Business Journal 6-28 Tetra Technologies plans to form a master limited partnership in which it will place most of its Compressco subsidiary assets. The Woodlands-based oil and gas company also said it will file its registration statement with the U.S. Securities and Exchange Commission for an IPO of MLP common units between late 2007 and early 2008. Tetra (NYSE: TTI) acquired Oklahoma City-based Compressco in June 2004 for about $93.5 million. The company, which has a petroleum engineering facility in Houston, manufactures production enhancement solutions for marginal and low pressure oil and gas wells. Devon Energy to Form Marketing and Midstream MLP PRNewswire 7-18 Devon Energy Corporation (NYSE: DVN) announced today that its board of directors has approved a plan to form a new, publicly-traded MLP. The MLP will own a minority interest in Devon's U.S. onshore marketing and midstream business. This business includes natural gas gathering and processing assets located in Texas, Oklahoma, Wyoming and Montana. Devon expects to file with the SEC a registration statement for the planned MLP in the third quarter of 2007. Exco to Spin-off E&P MLP BusinessWire 7-30 EXCO Resources, Inc. (NYSE:XCO) intends to pursue an MLP IPO to be formed by EXCO to own a substantial portion of EXCO's mature producing oil and natural gas properties located in the Appalachian, East Texas/North Louisiana, Mid-Continent and Permian Basin areas. EXCO currently expects that a registration statement for the initial public offering will be filed in the third quarter of 2007 and that the offering will close during the first quarter of 2008. Approximately $1.5 billion of the MLP's common units are expected to be offered to the public, subject to market conditions. EXCO will own the general partner of the MLP and expects to retain a substantial portion of the MLP's common units. El Paso to Spin-off MLP Houston Business Journal 8-07 Plans down the road for El Paso Corp. include an initial public offering of a pipeline master limited partnership, the company says. The Houston-based natural gas company also said it intends to file with the Securities and Exchange Commission for the offer and sale of about $500 million of common units, representing limited partner interest in its subsidiary, El Paso Pipeline Partners LP. El Paso (NYSE: EP) said it will own the general partner of the MLP and a substantial number of its common and subordinated units. El Paso Pipeline Partners initially will own interests in several interstate natural gas pipelines that are currently owned by El Paso Corp. On 8-01 Citigroup Upgraded MMP from Hold to Buy. On 8-03 Citigroup Upgraded OKS from Hold to Buy. On 8-14 SMH Capital Upgraded PAA to Buy; Citigroup Upgraded TLP from Hold to Buy; and Wachovia Upgraded TLP from Market Perform to Outperform. On 8-17 AG Edwards Upgraded DEP from Hold to Buy. On 8-20 Sharon Lui of Wachovia upgraded UCLP to "Outperform" from "Market Perform," and said she expects the natural-gas compression company to increase distribution by a compound annual growth rate of 15.4% from 2008 through 2012, assuming it acquires $4 billion worth of additional assets. 6-21 ETP declared a distribution of $0.80625/unit [compared to .7875 last quarter] payable 7-16 to holders of 7-02. 6-26 APL declared a distribution of $0.87000/unit [compared to .8600 last quarter] payable 8-14 to holders of 7-06. 7-12 KSP declared a distribution of $0.70000/unit [compared to .6800 last quarter] payable 7-24 to holders of 7-18. 7-13 TPP declared a distribution of $0.68500/unit [compared to .6850 last quarter] payable 8-07 to holders of 7-31. 7-17 OKS declared a distribution of $1.00000/unit [compared to .9000 last quarter] payable 8-14 to holders of 7-31. 7-17 DEP declared a distribution of $0.40000/unit [compared to .4000 last quarter] payable 8-08 to holders of 7-30. 7-17 EPD declared a distribution of $0.48250/unit [compared to .4750 last quarter] payable 8-09 to holders of 7-31. 7-18 KMP declared a distribution of $0.85000/unit [compared to .8300 last quarter] payable 8-14 to holders of 7-31. 7-18 CPNO declared a distribution of $0.44000/unit [compared to .4200 last quarter] payable 8-14 to holders of 8-01. 7-19 PAA declared a distribution of $0.83000/unit [compared to .8125 last quarter] payable 8-14 to holders of 8-03. 7-19 MWE declared a distribution of $0.53000/unit [compared to .5100 last quarter] payable 8-14 to holders of 8-08. 7-20 TLP declared a distribution of $0.50000/unit [compared to .4700 last quarter] payable 8-07 to holders of 7-31. 7-23 MMLP declared a distribution of $0.66000/unit [compared to .6400 last quarter] payable 8-14 to holders of 7-31. 7-24 NGLS declared a distribution of $0.33750/unit [compared to .3370 last quarter] payable 8-14 to holders of 8-02. 7-24 TCLP declared a distribution of $0.66500/unit [compared to .6500 last quarter] payable 8-14 to holders of 7-31. 7-24 SXL declared a distribution of $0.83750/unit [compared to .8250 last quarter] payable 8-14 to holders of 8-07. 7-24 XTEX declared a distribution of $0.57000/unit [compared to .5600 last quarter] payable 8-15 to holders of 8-02. 7-25 HLND declared a distribution of $0.73250/unit [compared to .7125 last quarter] payable 8-14 to holders of 8-08. 7-25 DPM declared a distribution of $0.53000/unit [compared to .4650 last quarter] payable 8-14 to holders of 8-07. 7-26 BPL declared a distribution of $0.81250/unit [compared to .8000 last quarter] payable 8-31 to holders of 8-06. 7-26 GEL declared a distribution of $0.22000/unit [compared to .2100 last quarter] payable 8-14 to holders of 8-06. 7-26 HEP declared a distribution of $0.70500/unit [compared to .6900 last quarter] payable 8-14 to holders of 8-06. 7-26 RGNC declared a distribution of $0.38000/unit [compared to .3800 last quarter] payable 8-14 to holders of 8-07. 7-26 MMP declared a distribution of $0.63000/unit [compared to .6125 last quarter] payable 8-14 to holders of 8-06. 7-26 EEP declared a distribution of $0.92500/unit [compared to .9250 last quarter] payable 8-14 to holders of 8-06. 7-26 WPZ declared a distribution of $0.52500/unit [compared to .5000 last quarter] payable 8-14 to holders of 8-07. 7-30 BWP declared a distribution of $0.44000/unit [compared to .4300 last quarter] payable 8-13 to holders of 8-06. 7-30 UCLP declared a distribution of $0.35000/unit [compared to .3500 last quarter] payable 8-14 to holders of 8-09. 7-30 NS declared a distribution of $0.95000/unit [compared to .9200 last quarter] payable 8-14 to holders of 8-07. 8-01 TGP declared a distribution of $0.53000/unit [compared to .4625 last quarter] payable 8-14 to holders of 8-09. 8-06 EROC declared a distribution of $0.3625/unit [compared to .3625 last quarter] payable 8-14 to holders of 8-08. KGS (QuickSilver Gas Services) ipo'ed on 8-07. The prospectus is available at roadshow site - http://www.retailroadshow.com/sys/launch.asp?qv=6213876415954419&k=81816801238 . Five million units were sold to public with 800K units going to land owners and 72.5% of units retained by the GP - KWK. KGS' facilities are located in the Ft Worth Basin and have a long reserve life - approx 30 years of field life. KGS is mostly located in eastern Hood County and north-eastern Sumervel County with a little in Johnson County. KWK has leases in eastern Hood County and Sumervel County with a little in Bosque, Erath, Hill and Johnson and Tarrant Counties. KWK has 265 thousand net acres under lease with only 15% having been drilled so far. KGS is a fee based business - with 11% of fees coming from third parties [there are seven third parties in the system now]. KGS will gather and process high BTU gas [wet gas]. KWK has been in business for 15 years - and most of KWK's growth has been and should continue to be organic growth. In 2004 KWK had zero production in the Barnett Shale. By Q1-07 production had grown to 52MMcf/day and by 2008 it is projected to be 141MMcf/day. The field has high BTU gas - liquids are 30% are more of the economics - and liquids prices are more dependant on oil prices than natural gas prices. KGS will piggyback on explosive growth projects by parent KWK. KWK has 700 BCF of proved reserves on he 265 thousand acres with inventory of 2000 more locations expected to be drillied with 25% growth/annum in proved reserves projected. Some Barnett Shale operators did not have the scale to gather and process their own gas - and in the southern part of the basin KWK/KGS will be the provider for gathering and processing to many of those third parties. KGS has 10 year contracts with KWK and other third party E&Ps. KGS will pursue other opportunites - but KGS does not need drop downs due to large projected organic growth in this basin alone. KWK History in the Basin: [1] KWK bought a used plant [the 75MMcf/day plant] in Q4-04 and now enhancing that closed plant [2] In 2005 KWK began pipeline system. KGS will own 2 inch to 20 inch pipes - going for 30 miles. [3] A plant with 125MMcf/day was constructed in 2006. KGS generates fees of 90 cents per MMBTU with CPI escalation. KGS' current capacity is 125 million/day - and processing 90 million/day now. Q3-07 capacity should be 200 million/day [the old 75 MMcf/day plant will be back on line]. The Q4-08 capacity is projected to be 325 MMcf/day - and pipeline is already sized to gather that amount. In the near term there is more pipeline expansioned planned to go to: [1] 'Dry system' for Lake Arlingtron [thus no need to process gas] and [2] Hill County expansions [also dry] has planned pipelines. [from the prospectus] "To support the near-term production growth that we anticipate from wells to be drilled in the Quicksilver Counties, we are pursuing the following additions to our operating asset base: A third processing unit, which we expect will provide 125 MMcf/d of additional processing capacity, thus increasing our total processing capacity to 325 MMcf/d by Q4-08; and the Cowtown Pipeline expansions to gather natural gas from new Quicksilver wells in the Quicksilver Counties and transport it to the Cowtown Plant." KGS budgeted approximately $168.9 million to cover all of our capital expenditures from January 1, 2007 through December 31, 2008. We intend to finance the projects mentioned above with our cash flow and with our revolving credit facility. Additionally, Quicksilver has the right to complete the construction of, and to operate, two new pipeline systems to gather and transport natural gas from new wells drilled in the Lake Arlington area of Tarrant County, which we refer to as the Lake Arlington Dry System, and in Hill County, which we refer to as the Hill County Dry System. We are obligated to purchase these pipeline systems from Quicksilver at fair market value within two years after the systems begin commercial operations. We anticipate that the Lake Arlington Dry System and the Hill County Dry System will be completed in 2008. [from page 8 of the prospectus] KGS estimate expansion capital expenditures for the twelve-month period ending 6-30-08 will be $83.1 million. These expenditures will include approximately $34.4 million associated with the construction of a third processing unit which we expect will provide 125 MMcf/d of additional capacity, and that we expect will become operational in Q4-08, and an additional $17.1 million at the Cowtown Plant for upgrades to the 75 MMcf/d natural gas processing unit, payments associated with the completion of the 125 MMcf/d natural gas processing unit, additional compression horsepower and other expansion projects. Additionally, we expect to spend $31.6 million associated with the expansion of the Cowtown Pipeline system. We expect to connect 228 Quicksilver wells to our system during this period. These costs are projects that we expect to yield sufficient rates of return to construct based on Quicksilver’s current drilling program for the twelve-month period ending June 30, 2008. [prospectus page 59] Financial overview: Our objectives [1] increase distributions; [2] have strong balance sheet; and [3] pursue growth opportunites. KGS will had $300K debt upon IPO - $150 million revovling credit facility - $14 million in cash on hand after IPO if there is an over-allotment sale of units. KGS Units: Publicly owned 21.3%; Private placements 3.5%; KWK to own 75.2% [or 73.5% if there is an over-allotment sale of units] The 12 month EBITDA projection is for $41 million/year [starting July 1, 2007] with $6 million interest costs. The 2008 DCF projection of $29.1 million after coverage [my calculation: $6 million interst and $5.9 million maintenance cap ex - but that number does not match with figures below] [From the prospectus: We estimate maintenance capital expenditures for the twelve months ending June 30, 2008 will be $2.5 million based on the average level projected for the three-year period ending June 30, 2010. These expenditures include well connect costs associated with maintaining volume throughput on our Cowtown Pipeline and our Cowtown Plant.] DCF Valuations: $29.1 million DCF times 21.3% [the amount applied to public units] = $6.1983 million of DCF to the public shares. Then take that $6.1983 million and divided by 5 million units to get $1.23966 DCF/unit. KGS had a minimum distribution of 30 cents which results in a $1.20/annum distribution. This puts the distribution/DCF ratio at 96.7% with the sector average at 86%. This ratio looks bad. A $20 price puts the yield at 6%. A $21 pirce puts the yield at 5.7%. Sector average yield on 7-26 = 5.25%. A $20/unit price puts the price/DCF ratio at 16.12 with the sector average price/DCF ratio at 14. A $21/unit price puts the price/DCF ratio at 16.93 [This ratio is too high] Speculation: The numbers that KSG are using may be conservative - they are probably covering their own @ss for legal reason and thus giving us low ball numbers. So perhaps one should do not let the bad looking distribution/DCF and price/DCF scare you off. But, if the estimates are not conservative, then KGS is slightly over priced [at $21.00] compared to other newbie MLPs. On a pro forma basis as of March 31, 2007, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $90.5 million, or $3.85 per common unit. Minimum Quarterly Distribution. . . . $0.3000 Second Target Distribution . . . . . . . above $0.3450 up to $0.3750 KSG gets 85% - 2% to GP and 13% in IDRs to the GP Third Target Distribution . . . . . . . . . above $0.3750 up to $0.4500 KSG gets 75% - 2% to GP and 23% in IDRs to the GP Thereafter . . . . . . . . . . . . . . . . . . . . above $0.4500 ....................... KSG gets 50% of the increase in distribution
Minimum estimated EBITDA necessary to pay cash distributions at the initial distribution rate . $ 37.9 million Interest coverage ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.7x Leverage ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7x Gathering Fees: We will receive an average fee of $0.48/Mcf for the twelve months ended 6-30-08 as compared to $0.42/Mcf for the year ended 12-31-06. [my calculation: 141 MMcf/day times .48/day fee = $67,680. Then take $67,680 times 365 days = $24,703,200/year]. Processing Volumes: We will process an average of 141 MMcf/d of natural gas for the twelve months ending June 30, 2008 compared to 37 MMcf/d for the year ended December 31, 2006 and 53 MMcf/d in the first quarter of 2007. The increased volumes estimated for the twelve months ending June 30, 2008 represent the contribution from Quicksilver's forecasted drilling program as well as volumes associated with existing contracts in place with third party producers, but excludes those volumes which do not require processing. Processing Fees: We will receive an average fee of $0.59/Mcf for the twelve months ended June 30, 2008 as compared to $0.48/Mcf for the year ended 12-31-06. [my calculation: 141 MMcf/day times .59/day fee = $83,190. Then take $83,190 times 365 days = $30,364,350/year]. Pipeline Operating Fee: We will receive an aggregate fee of $900,000 for the twelve months ended June 30, 2008 from Quicksilver for operating the Lake Arlington Dry System and Hill County Dry System on Quicksilver's behalf. [My calculation - total fees = $55,967,550 (24,703,200 + 30,364,350 + 900,000)] Operating and Maintenance Expense. We estimate total operating and maintenance expense for the twelve months ending 6-30-08 will be $11.6 million as compared to $7.5 million for the year ended 12-31-06. These expenses are comprised primarily of direct labor, insurance, property taxes, repair and maintenance, utilities and contract services. The increase in operating and maintenance expenses estimated for the twelve months ending 6-30-08 reflects the costs associated with the addition of the 125 MMcf/d gas processing unit in Q1-07. We expect that operation and maintenance costs on the recently completed Cowtown Plant addition will remain relatively stable independent of the volumes through the system but will fluctuate slightly depending on the activities performed during a specific period. General and Administrative Expense. We estimate general and administrative expense for the twelve months ending 6-30-08 will be $3.8 million pursuant to the omnibus agreement and the services and secondment agreement which includes both costs reimbursable to Quicksilver for services performed on our behalf as well as public company expenses. Texas Margin Tax. We estimate Texas margin tax payments for the twelve months ending 6-30-08 will be $0.2 million based on a 1.0% tax rate on a maximum of 70% of our projected revenues for the year ended 12-31-07. My calculation - An estimate of EBITDA: $55,967,550 from fees minus $11,600,000 (operations) minus $3,800,000 (GnA) = $40,567,550 [This matches up well with the KGS EBITDA estimate] My calculation - A rough estimate of cash flow: $55,967,550 minus $11,600,000 (operations) minus $3,800,000 (GnA) minus $6,000,000 (interest) minus $200,000 (Tx Margin Tax) minus $2,500,000 (maintenance cap ex) = $31,867,550 [This is $2.7 million higher that KGS DCF estimate, but I may need to subtract a portion of the two year $168.9 million growth cap ex from this number, and I am uncertain of that math.] The CAGR estimates were influenced by those attained from Yahoo, but are primarily based on those from AG Edwards. The DCF estimates for ATN, BBEP, EVEP and LINE are from AG Edwards. Those for CEP and LGCY are based on their current distributions, where I used dcf/.9 = distribution [which is approx the sector average] to arrive at a DCF. And the EVEP 2008 EPS estimate was also absent at Yahoo - so I used the current trend to estimate that. This whole sector is brand new, with ONLY LINE having paid a distribution in 2006. And the abscence of a track record causes the CAGR estimates to be varied and undependable. The unit price gains in this sector have been too high to ignore. The P/E ratios still look very attractive relative to standard MLPs. And many of the CAGR estimates [estimate that are so high that I am not using them for my metrics] for most E&P's are significantly higher than most regular MLPs. At the moment, I still have a problem believing the CAGRs would be higher for sustainable periods. E&P's can purchase assets at lower enterprise values to EBITDA ratios and thus make more accretive acquisitions compared to midstream MLPs, where the purchase of these acquistions by traditional MLPs now come with higher price tags and lower accretion. I would suspect that over time, the EBITDA multiples for E&P assets will grow too. Because of the hyper-accretiveness of new acquisitions, those E&P MLPs with the newest and the highest percentage of acquisitions will be the ones that will probably have the highest unit price appreciation. Thus the Forecaster Model - which uses valuation and CAGR differences to mathamatically find MLPs that are undervalued - would logically be less predictive in this sub-sector. EVEP Reports Net Income of $0.93/unit Business Wire 8-14 EV Energy Partners reported net income of $12 million, or $0.93 per basic and diluted weighted average unit outstanding, for the quarter ended June 30, 2007. Included in net income was $3.4 million of non-cash gains on commodity derivatives and $0.3 million of non-cash unit based compensation costs contained in general and administrative expenses. Adjusted EBITDA for Q2-07 was $13.7 million. Production for the quarter was 2.14 Bcf of natural gas and 35 MBbls of crude oil and natural gas liquids, or 2.35 Bcfe, a 75% increase over Q1-07 production of 1.34 Bcfe. BBEP Reports Loss of $0.04/unit Business Wire 8-14 BreitBurn Energy Partners reported EBITDA in Q2-07 totaled $12.2 million. Including unrealized losses on derivative instruments of $8.4 million, net loss for the second quarter totaled $1.1 million, or 4 cents per diluted limited partnership unit. During the second quarter, average daily production increased 24% from the first quarter of 2007 to 5,889 boe per day (boe/d). Aggregate production during the second quarter totaled 536,000 boe. Excluding the effect of derivatives, our oil, natural gas and natural gas liquid sales were $32.4 million. Lease operating expenses for the second quarter totaled $10.7 million, or $19.98 per boe, and are 10 cents per boe higher than the first quarter. Depletion, Depreciation and Amortization (DD&A) expense for the second quarter totaled $4.5 million, or $8.42 per boe compared with $3.1 million, or $7.13 per boe, for the first quarter of 2007. LINE Reports Loss of $0.29/unit vs. Gain of $0.36 in Q2-06 PRNewswire 8-13 Linn Energy, LLC reported Adjusted EBITDA in Q2-07 of $36.6 million compared to $33.5 million in Q1-07 and 14.9 million in Q2-06. Total production increased 219%, to 6.2 Bcfe from 2.0 Bcfe in Q2-06. Production increased from drilling and acquisitions resulting in an increase in gas, oil and NGL sales of 264%, to approximately $49.2 million, compared to $13.5 million in Q2-06. CEP to Acquire Newfield Exploration Oil & Gas Properties in the Cherokee Basin PRNewswire 8-02 Constellation Energy Partners announced that it has signed a definitive purchase agreement to acquire certain coalbed methane properties from Newfield Exploration for an aggregate purchase price of $128 million, subject to purchase price adjustments. The properties are located in the Cherokee Basin in Oklahoma. The Newfield properties have estimated proved reserves of 45 Bcfe with a reserve life index of approx 13 years. Current net production is approximately 10,000 Mcfe per day and current net sales are 9,300 Mcfe per day. There are over 600 net producing wells on the properties with an average working interest of approximately 94% and approx 350 miles of pipeline gathering systems. On Citigroup Upgraded CEP from Hold to Buy. On 8-09 RBC Capital Markets Upgraded LBCY from Sector Perform to Outperform. On 7-18 LGCY declared a distribution of $0.42000/unit [compared to .4100 last quarter] payable 8-14 to holders of 7-31. On 7-19 LINE declared a distribution of $0.57000/unit [compared to .5200 last quarter] payable 8-14 to holders of 8-02. On 7-25 EVEP declared a distribution of $0.50000/unit [compared to .4600 last quarter] payable 8-14 to holders of 8-06. On 7-24 CEP declared a distribution of $0.46250/unit [compared to .4625 last quarter] payable 8-14 to holders of 8-07. On 7-27 BBEP declared a distribution of $0.42250/unit [compared to .4130 last quarter] payable 8-14 to holders of 8-07. On 8-02 FMO announced that it is increasing the quarterly dividend by 1.43% to $0.355 per share, effective with the next distribution to be paid on October 31, 2007 to shareholders of record as of October 15, 2007. The increased dividend compares to the $0.35 per share for the last quarterly dividend. FMO's net asset value per share has grown from $19.10 at its inception in December 2004 to $25.90 as of July 31, 2007. Tortoise Announces Dividend Increases PRNewswire 8-13 TYG declared a dividend of $0.55 per share, compared to $0.545 in the previous quarter and $0.51 in the same quarter of the prior year. The dividend will be distributed on Sept. 4, 2007 to stockholders of record on Aug. 23, 2007. TYN declared a dividend of $0.365 per share, compared to $0.36 in the previous quarter. The dividend will be distributed on Sept. 4, 2007 to stockholders of record on Aug. 23, 2007. TYY declared a dividend of $0.41 per share, compared to $0.405 in the previous quarter and $0.38 in the same quarter of the prior year. The dividend will be distributed on Sept. 4, 2007 to stockholders of record on Aug. 23, 2007. HPGP Reports Net Income/share of $0.05 PRNewswire 8-08 Hiland Holdings GP, LP reported quarterly net income for the three months ended June 30, 2007 of $1.1 million ($0.05 per limited partner unit-basic) compared to net income of $0.2 million for the three months ended June 30, 2006 (includes its predecessor, Hiland Partners GP, LLC). Hiland Holdings GP, LP commenced operations September 25, 2006 upon successful completion of its initial public offering and the concurrent contribution of certain interests from its predecessor entity and its contributing parties. Net income before minority interest was $1.8 million in Q2-07 compared to $3.2 million in Q2-06. The decrease in net income before minority interest is primarily due to additional depreciation expense and interest expense incurred as a result of the acquisition of the Kinta Area gathering assets effective May 1, 2006 and interest expense related to borrowings for organic growth projects, offset by increased sales volume from the Kinta Area, Bakken and Eagle Chief gathering systems. Plains GP Holdings files for $400 million IPO Reuters 8-31 Plains GP Holdings LP, whose cash-generating assets are partnership interests in Plains All American Pipeline LP, filed with regulators on Friday to raise up to $400 million in an initial public offering. Citi and Lehman Brothers are underwriting the IPO. The filing did not reveal how many common units the company plans to sell or their estimated price, as those details are expected in future filings. Plains GP said it plans to list its common units on the New York Stock Exchange but did not disclose its expected symbol. Upon completion of the offering, Plains GP will own all of the Class A units in PAA, the 2% general partner interest in all of the incentive distribution rights and 15 million common units representing a 12.7% limited partner interest in PAA. On 6-21 ETE announced a distribution of $0.3725/unit payable 7-19 to unitholders of 7-02. On 6-26 AHD declared a distribution of $0.2600/unit payable 8-17 to holders of 7-06. On 7-17 EPE declared a distribution of $0.3800/unit [compared to .3100 last quarter] payable 8-10 to holders of 7-31. On 7-24 XTXI declared a dividend of $0.2300/unit [compared to .2200 last quarter] payable 8-15 to holders of 8-02. On 7-26 BGH declared a distribution of $0.25000/unit [compared to .2400 last quarter] payable 8-31 to holders of 8-06. On 7-27 MGG declared a distribution of $0.27600/unit [compared to .2615 last quarter] payable 8-14 to holders of 8-06. On 7-30 NSH declared a distribution of $0.34000/unit [compared to .3200 last quarter] payable 8-16 to holders of 8-07. NOTE #1: This page is ment to be a supplement for those already getting monthly sector updates from another source. Data entry errors sporadically happen here. There are metrics like Debt/Market Cap, system capacity useage, organic growth in process to total market cap, and the GP/LP split ratios that should not be ignored but are not covered here. NOTE #2: The operator of this site owns units in BWP, EPD, ETP, DPM, MWE and PAA, and units in GP MGG, and candidates for future acquisition include KSG, TGP and WPZ - and this could distort the coverage of those MLPs. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||