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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 m | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||