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Prior Updates Mar 06 Feb 06 Jan 06 2005 Updates Dec Nov Oct Sept Aug July Jun May Aprl Mar Feb Jan 2004 Updates Dec Nov Oct Sept Aug July Jun May Intro MLP & Energy News Oil Online MLP Blog Petro News Util/MLP Blog Yahoo News MLP Intro Wachovia Primer R James Primer Alerian Primer Market Stats MLPs at Yahoo GPs at Yahoo MLPs at CNN MLPs at Excite MarketWatch MLPs at MSN MLPs at WSJ Factoids April March February January REIT Updates April Off/Ind/Apt April Retail/Hlth Bank Updates April March February January |
The 2007 DCF estimates from all three brokerages have been added, and a new 2006 composite or consensus was calculated. This data is fresh off the press. A BIG thanks to ARB and Euro, who contributed data for this effort. I have added a new spreadsheet with predictive metrics to the bottom of the valuation tables - or just above the 'news' updates. I welcome your feed-back on this new information. Valuations for GP's EPE, ETE, MGG, & XTXI were added 4-14 in a spreadsheet just above the CEF spreadsheet. I had to make some guesses in the dividends for ETE [which announced an 80 cent per year dividend initially, but that data could be out-dated] and MGG [where I found the information on the Yahoo message board] - and welcome any corrections to this data. MarkWest [MWP] still lacks EPS data - and thus was not added. APL and VLI have upcoming GP IPOs. EPS estimates were updated 4-21, with large changes in ETP [going up] and HLND and XTEX [both going down]. Distribution announcements for Q2 have started, with EPD announcing an increase on the 17th, CPNO and NBP on the 18th, KMP & TLP on the 19th, PAA & SXL on the 20th, MWE, PPX and XTEX on the 21st, VLI on the 24th, HEP on the 25th, APL, HLND, MMG and MMP on the 26th, WPZ on the 27th - ETP announced last month. The Q2 distributions are currently used in my yield calculations below. For March the MLP midstream sector is up 2.13%, with pipelines up 2.40%. The sector average yield is 6.56% [vs. 6.68% at February's end - down 12 basis points], with the average pipeline yielding 6.48% [vs. 6.61% at February's end - down 13 basis points] and the closed-end fund average yield is 6.67%. With the ten year treasury at 4.85%, the MLP midstream spread is at 171 basis points [vs. 213 on 2-28] and the pipeline spread is 163 [vs. 206 on 2-28]. The 89 point spread shrinkage year to date is a warning. With the ten year treasury ending February 4.55%, the MLP midstream spread was at 213 basis points and the pipeline spread was 206. As of 12-30, with the ten year treasury at 4.40% and the MLP sector yielding 6.92%, the spread of MLPs over the yield of the 10 year stood at 252 basis points. The spread on 11-30 stood at 230 basis points after ending October at 188, September at 174, August at 208, July at 159, June at 211, May at 216, April at 195, March at 156, February at 152 and ending January at 178. For 2005 the average [month-ending] spread was 193. Pacific Energy Partners to Build Crude Oil Pipeline to Cheyenne, Wyoming BusinessWire 4-03 Pacific Energy Partners announced that Rocky Mountain Pipeline System LLC (RMPS) has signed a transportation agreement with Frontier Oil and Refining Company, a subsidiary of Frontier Oil (FTO), pursuant to which RMPS will construct a new pipeline system from Guernsey to Cheyenne, Wyoming in exchange for Frontier Oil's ten year firm commitment to ship 35,000 barrels per day to support this expansion project. This project is a natural extension of Pacific Energy's existing pipeline system serving Guernsey and Fort Laramie. Construction will begin in the second quarter of 2006 and is expected to be completed in the second quarter of 2007. The estimated cost of the project is $59 million, $31 million to be spent in 2006 and the remaining $28 million to be spent in 2007. Initial capacity will be 55,000 barrels per day, which can be expanded to a capacity of 90,000 barrels per day. Pacific Energy Partners to Construct Crude Oil Pipeline to Salt Lake City BusinessWire 4-04 Pacific Energy Partners announced that Rocky Mountain Pipeline System LLC (RMPS) is proceeding with the expansion of its crude oil pipeline system from the terminus of Frontier Pipeline near Evanston, Wyoming to the Salt Lake City, Utah refining complex. The new pipeline will be constructed in two phases, with construction of the first phase scheduled to begin immediately and be completed in the fourth quarter of 2006. The completion of the first phase will add additional capacity into Salt Lake City of approximately 12,000 barrels per day. The second phase is expected to be completed in October, 2007. Capacity of the completed pipeline will be approximately 95,000 barrels per day. The first phase of the Salt Lake City pipeline project is expected to cost $32 million. However, Pacific Energy's total 2006 expansion capital budget of $106 million is being increased to $118 million to reflect certain costs associated with the second phase of the project, which are now expected to be incurred in 2006. The total cost for both phases of the project is expected to be approximately $77 million. Kinder Morgan Energy Partners Expanding CALNEV System to Las Vegas Reuters 4-07 Kinder Morgan Energy Partners [KMP] announced it will invest approximately $15 million to expand the CALNEV system, which will increase pipeline capacity for gasoline, jet fuel and diesel into Las Vegas, to approximately 156,000 bpd by Q4-07. This project is in addition to about $10 million in upgrades on the CALNEV system that were announced previously this year. Combined, the $25 million in capital improvements are expected to provide sufficient pipeline capacity for the Las Vegas market for the next several years. KMP is also exploring a $300 to $400 million future expansion that would increase capacity on the pipeline to approximately 220,000 bpd by 2010. The approximately 550-mile CALNEV system originates at KMP's Colton, Calif., terminal and is primarily comprised of an 8-inch diameter pipeline that transports jet fuel, a 14-inch diameter pipeline that transports gasoline, diesel and jet fuel, and terminal facilities in Barstow, Calif., and Las Vegas. Its current transportation capacity is approximately 140,000 bpd. Williams Partners Buys Assets & Files to Sell 7 Million Units Businesswire 4-07 Williams Partners on Friday filed with securities regulators to offer 7 million common units representing limited partner interests in the company, a 30-day over-allotment option for an additional 1.05 million units. Stats at Yahoo showed 14 million shares outstanding prior to this announcement. On 4-06 Williams Partners announced that it has agreed to acquire for $360 million a 25.1% interest in Williams' Four Corners LLC subsidiary. For 2005, the adjusted EBITDA attributable to a 25.1 percent interest in Williams Four Corners LLC totaled $38.4 million. Assets comprising the Four Corners system include: [1] a 3,500-mile natural gas gathering system in the San Juan Basin in New Mexico and Colorado with capacity of 2 billion cubic feet per day; [2] the Ignacio natural gas processing plant in Colorado and the Kutz and Lybrook natural gas processing plants in New Mexico, which have a combined processing capacity of 760 million cubic feet per day; and [3] the Milagro and Esperanza natural gas treating plants in New Mexico, which are designed to remove carbon dioxide from up to 750 million cubic feet of natural gas per day. Situated in the prolific San Juan Basin, the Four Corners system is one of the largest integrated natural gas gathering systems in the country," said Alan Armstrong, COO of the GP of Williams Partners. ETP Reports Q2 Net Income/Unit of $1.36 vs $.68 in Q2-05 Press release of 4-07 Energy Transfer Partners (ETP) reported record net income for Q2-06 ending 2-28 of $250.8 million, as compared to net income of $87.6 million for Q2-05, an increase of $163.2 million or about 186%. EBITDA, as adjusted, for Q2-06 was $314.8 million versus the $145.3 million reported for Q2-05, an increase of $169.5 million or approximately 117%. For the six months ended 2-28-06, net income increased $252.4 million or about 214% to $370.6 million as compared to $118.2 million for the six months ended 2-28-05. EBITDA, as adjusted, increased $296.9 million or about 138% to $511.9 million for the six months ended February 28, 2006 as compared to $215.0 million for the six months ended February 28, 2005. Some $50 million of Q2's income came from gains on the mark-to-market adjustments of hedges. My Notes from ETP's Conference Call Jay Hatfield of HAK Capital asked, on ETP's $650 to $710 EBITDA guidance - what is a good number to use for a base? ETP: We have not included any income from new projects in those numbers - and no weather anomalies. Every year has an anomaly. As we look back on our original 2006 projections, we are comfortable with 660. Jay: For the additional expansion of XTO project - can we forecast another $60 million in EBITDA? ETP: That is a logical assumption. Jay: There could be large return on invested your capital? ETP: Yes. Jay: What is repeatable about the anomalies? ETP: We use money gain from those to pay down debt, or use money for new projects - decreasing our needs for new units. . or new equity offerings. Jay: In your initial guidance, you gave a distribution guidance of an increase of more than 10% - given your large increase already, it seems trivial guidance at this point - is there new timing for your distribution expectations? ETP: We do not forecast distribution increases - our board will fire us if we did. The new pipelines are being integrated - and they are performing better than anticipated - the company is performing better than expected - and you can use that to build your own distribution expectations. ETP has become MORE weather sensitive - and even given that handicap of the warm weather, ETP has produced these great numbers. Eves Sigel with Wachovia noted that based on ETP's $710 EBITDA guidance - that implies a 'flat' second half. ETP: Our second half will be up. Kevin Gallagher from RBC noted that. . on the 42 pipe expansion . . you must be anticipating having a big chunk of market. ETP: No one else in Barnett Shale can provide our level of service. Other pipelines take gas from one glutted area to another glutted area - so we will get most of the business. Kevin inquired about the recent "shelf filing" ETP: We had used up last shelf. We are not signaling anything - this shelf should last 3 years. We do have a planned public debt offering in the summer. Kevin: What was your Maintenance Cap-ex for Q1? ETP: $19.6 million. Ron Londe AG Edwards wanted ETP to give more details on the way ETP is hedging - and how that will change when Houston contract expires. ETP: The way those contracts are structure - our largest customer can call on up to 1.8 BCF/day - which can only be filled with a withdrawal from Bammel. We acquired the Houston pipeline knowing that we had this responsibility. Most of the load is humane need. We sell [or hedge] on Houston based index price. We forecast how much we will need for the winter - and start injecting in the summer. We sell/hedge based on Dec price. The contract expires this time next year. If renewed, and this customer has few alternatives so we expect are renewal - and as you know we are not a fan of merchant business. For the new contract, we will not take title of the BTUs. We will charge to transport gas to Bammel for storage, then charge to store at Bammel, then charge to transport from Bammel. We will still use Bammel. Ron: do you anticipate the new contract will be more or less profitable? ETP: I think it will be more profitable. The current contract requires ETP to own approx $600 million in gas. With a new contract where ETP does not have to buy/own the gas, ETP's liquidity needs will go down. Ron: Did this [Bammel storage] help you in Q1 - having the gas on hand? ETP: Bammel is fabulous facility. There was chaos after the hurricanes. The Houston natural gas suppliers locked their fences and went home. The gas which we had in storage allowed us opportunites for profits last year. Jeff Murser of Raymond James asked how does ETPs approach to trading/marketing differ from its approach to hedging? ETP: Marketing is buying and selling molecules. Marketing is moving the gas. Jeff: Volumes on the Houston pipeline is very seasonal. What is volume swing? ETP: Volume is up to one billion cubic feet per day in the winter. Devin Gagan with ZLP asked about when the Barnett Shale pipelines would be full. ETP: The 42 inch pipe moves gas other than Barnett Shale. Producers will not tolerate having gas shut in. So it is reasonable that other pipes will be built, and will be announced. But producers will not commit long term to one pipe. If you look at what ETP pipes do - it is hard to see how we will not fill up. Devin: On your distribution coverage ratio of 1.2 to 1.15, this ratio - had been 1.25. Sounds like you are comfortable going down on that ratio. ETP: We look at our life cycle - our appetite for capital - and look at our credit ratings. So we balance a lot of needs. Eves Segal of Wachovia asked how much gas ETP has in storage. ETP: 21 BCF. Eves: Have you started injecting? ETP: Yes. Eves: Are there expansion opportunities in regard to having more processing facilities? ETP: In connection with the 42 inch pipeline, we will have opportunities to treat gas - and these are sweat contracts because it adds gas to out pipes. Eves: What about the long lead times for construction? ETP: Steel costs are up - it is now harder to buy pipe. Lead times to buy pipes getting longer. For pipes we have announced, we will anticipate pipe will take longer to get. Eves: What about your 2007 Guidance? ETP: It is too early. Jeff Davies with Wachovia asked about any update with conversations with the debt agencies? ETP: We can not update. Jeff: Look at credit stats compared to others - you want an investment grade - are their any things that you can talk about - what are the sticking points? ETP: We have filed the info with the SEC - numbers are now not just projections - which may help. Kinder Morgan Inc. Receives Commitments for Chicago-Area Natural Gas Pipeline PRNewswire 4-12 KMI announced that it has entered into a long-term, firm transportation agreement with The Peoples Gas Light and Coke Company, an affiliate of Peoples Energy, that will support construction of a new $13 million natural gas pipeline that will be built by KMI to serve the Chicago market. Peoples has contracted for all of the 360,000 dekatherms per day of capacity on the proposed 28-mile Kinder Morgan Illinois Pipeline, which will run from Beecher, Ill., to the Chicago city limits near Burnham, Ill. The project combines construction of a new pipeline and a long-term capacity lease on Natural Gas Pipeline Company of America, a wholly owned subsidiary of KMI. Pending regulatory approval, the pipeline is expected to be available for service on Nov. 1, 2007. MLPs Increases Distributions Enterprise Products Partners announced an increase in its quarterly cash distribution rate to partners to $0.445/unit. This distribution represents an 8.5% increase over the $0.41/ unit quarterly distribution paid of Q1-05. Northern Border Partners is increasing its cash distribution by $0.08 per unit to $0.88 per unit. Copano Energy announced a distribution of $0.60/unit. This distribution is $0.05 above Copano Energy's distribution for the fourth quarter of 2005 and $0.20 above the minimum quarterly distribution of $0.40 per unit. TransMontaigne Partners announced a distribution of $0.43/unit. This distribution is an increase of $0.03/unit over the distribution paid for the period ended December 31, 2005. Kinder Morgan Energy Partners increased its distribution $0.81/unit from $0.80 per unit. The distribution represents a 7% increase over Q1-05's distribution of $0.76. Plains All American announced a cash distribution of $0.7075/unit. The distribution represents an increase of approximately 11.0% over the quarterly distribution of $0.6375 paid in May 2005 and approximately 2.9% over the February 2006 distribution of $0.6875. Sunoco Partners increased its distribution to $0.75/unit, an increase of $0.0375 per partnership unit over the preceding quarter ($0.15 annualized increase). MarkWest declared a quarterly cash distribution of $0.87/unit. This is an increase of $0.05 per unit over the previous quarter. CrossTex's distribution will increase from $0.51/unit to $0.53/unit. Pacific Energy Partners declared a distribution of $0.5675/unit. It is 2.3% greater than Q4's and is 10.7% greater than Q1-05's. Valero announced that it has declared a distribution of $0.885/unit, or $3.54/unit annually. This distribution represents an increase of $0.03 per unit, or 3.5%, over the distribution for Q4-05. Distributable cash flow available to limited partners covers the distribution to the limited partners by 1.21 times for Q1. Holly Energy Partners announced its distribution for Q1 of $0.64/unit vs. prior $0.625/unit. Hiland Partners announced its would increase from $0.625/unit $0.65/unit. Magellan Midstream Partners increased the partnership's quarterly cash distribution to %0.565/unit. The first-quarter distribution represents a 17.7% increase over the first- quarter 2005 distribution of 48 cents per unit and a 2.3% increase over the fourth-quarter 2005 distribution of 55.25 cents. Atlas Pipeline Partners reported a distribution for Q1 of $0.84/unit. This is the eighth consecutive distribution increase for the Partnership. The $0.84 distribution per common limited partner unit represents a 12% increase compared with the $0.75 distribution declared for the prior year first quarter. Williams Partners L.P. announced an 8.6% increase to its distribution to unitholders to 38 cents/unit. KMP Reports Earnings Businesswire 4-19 KMP reported a 10 percent increase in first quarter net income to $246.7 million, or $0.53 per unit, compared to $223.6 million, or $0.54 per unit, in the first quarter of 2005. Before certain items in the first quarter of 2005, KMP recorded net income of $250.7 million, or $0.67 per unit. Earnings before DD&A were $481.1 million, approximately 8 percent better than the $446.4 million recorded in the first quarter of 2005. The Products Pipelines segment produced first quarter earnings before DD&A of $125.9 million, up slightly from the comparable period a year ago. Total refined products revenues increased by 5.5% quarter over quarter and volumes were up 0.8 percent. Volumes on CALNEV were up 11.8%. The Natural Gas Pipelines segment delivered an increase of 16% in Q1 earnings before DD&A to $143.5 million versus $123.7 million for Q1-05. The CO2 segment produced first quarter earnings before DD&A of $121.7 million, down slightly from the first quarter a year ago and just below plan for the quarter. The Terminals segment reported a 21 percent increase in first quarter earnings before DD&A to almost $90 million, compared to $74.2 million for the same period a year ago. KMP is still hopeful it will declare cash distributions of $3.28 per unit for 2006. Citi Cuts KMP to Hold Citigroup 4-20 KMP's adjusted EBITDA for the Q1-05 was $417.5 million, 2% below our estimate. The shortfall was largely due to lower-than expected results from the Products Pipeline segment and the CO2 segment. Given the expected shortfall in the CO2 segment, we think the partnership will have difficulty meeting its stated 2006 distribution target of $3.28 per unit. Therefore we are lowering our 2006 distribution estimate to $3.25 and our 2007 distribution estimate to $3.30 per unit. As a result of these lower distribution expectations we are lowering our rating to Hold/Medium Risk (from Buy/Medium Risk) and lowering our price target by $1.00 to $50.50 per unit. The equity value for Kinder Morgan derived by our two-stage DCF model is $47.90 per unit (previously $51.62). The basic inputs used in our DCF valuation model include our assumptions that distributions will increase by 6.95% annually (previously 7.5%) over the next five years and by 3% annually beginning in the sixth year and extending into perpetuity. Energy Transfer to Acquire Titan Propane Businesswire 4-20 Energy Transfer Partners announced that it has signed an agreement to acquire all of the propane operations of Titan Energy Partners LP and Titan Energy GP LLC. The Partnership expects this transaction to be immediately accretive at a value of approximately $0.10 to $0.15 per common unit. The all-cash transaction will initially be financed through borrowings under the Partnership's Revolving Credit Facility. The Titan propane assets primarily consist of retail propane operations in 33 states. The operations are conducted from 146 district locations, and represent quality assets located in high growth areas of the U.S. Sunoco Reports Q1 Results PRNewswire 4-20 Sunoco Logistics Partners announced net income for Q1-06 of $18.4 million, or $0.66 per limited partner unit on a diluted basis, compared with $15.3 million for Q1-05, or $0.59 per limited partner unit on a diluted basis. The 20.4% quarter over quarter increase of $3.1 million was due mainly to the operating results of acquisitions completed in 2005, higher Western Pipeline System lease acquisition margins, and an increase in total shipments in the Eastern Pipeline System, partially offset by $2.9 million of costs related to the relocation of the Western area headquarters from Tulsa Sugar Land, Texas. EPCO Proposes to Eliminate TEPPCO'S 50% GP Incentive Distribution Rights Businesswire 4-20 Texas Eastern Products Pipeline Company, LLC, the general partner of TPP, announced that EPCO, Inc., which with its affiliates own the general partner of TEPPCO, has submitted to the Audit and Conflicts Committee of the general partner's Board of Directors a proposal to eliminate the general partner's incentive distribution right to receive 50% of total cash distributions with respect to that portion of TEPPCO's quarterly distribution to limited partners that exceeds $0.45 per common unit. Under the terms of the proposal, the general partner's incentive distribution rights would be capped at 25% of the total cash distributions with respect to that portion of TEPPCO's quarterly cash distribution to partners that exceeds $0.325 per unit. In exchange for the agreement to eliminate the 50% incentive distribution right, TEPPCO's general partner would receive a number of newly-issued TEPPCO common units whose distributions would approximate the amount of actual cash distributions foregone by the general partner from eliminating the 50% incentive distribution right at the time such change, if any, in the incentive distribution right is instituted. Valero L.P. Reports Q1 Net Income of $0.75/unit vs.77/unit in Q1-05 Businesswire 4-24 Valero L.P. today announced net income applicable to limited partners of $35.3 million, or $0.75 per unit, for Q1-06, compared to $17.8 million, or $0.77 per unit, for Q1-05. Distributable cash flow available to limited partners for the first quarter was $50.2 million, or $1.07 per unit, compared to $23.1 million, or $1.00 per unit for the first quarter of 2005. The increase in net income and distributable cash flow was primarily due to the acquisition of Kaneb completed on July 1, 2005. Valero L.P.'s Q1-05 results do not include any results from Kaneb. Valero completed the sale of its Australia and New Zealand subsidiaries for $68.6 million. Results of the divested businesses have been classified as discontinued operations on the income statement for the first quarter of 2006. The bunkering businesses at St. Eustatius and Point Tupper did better than anticipated, as did several of the other assets acquired with Kaneb. VLI also benefited from lower than expected natural gas costs. With regard to our Burgos pipeline construction project in South Texas and northeastern Mexico, VLI has completed construction of the pipeline segments connecting our Edinburg and Harlingen, Texas terminals to CITGO's terminal in Brownsville, Texas. VLI is nearly finished with the Mexican portion of this project and we expect the Burgos project to be complete by July 1, 2006. Effective January 1, 2006, the partnership successfully completed the acquisition of Valero Energy's 23.77 percent interest in a 57-mile crude oil pipeline located in Illinois for approximately $13 million. MWE to Offer Units Reuters 4-25 MarkWest Energy Partners LP may offer up to 3.3. million units in a secondary offering, according to a regulatory filing on Tuesday. EPD Reports Earnings BusinessWire 4-24 EPD reported a 22% increase in net income for Q1-06 to a record $134 million, or $0.28/unit, from $109 million, or $0.25/unit in Q1-05. Distributable cash flow for Q1-06 was $218 million compared to $251 million for Q1-05, which included $42 million from the proceeds from sale of assets. DCF for Q1-06 provided 1.1 times coverage of the distributions. Revenue for Q1-06 increased 27%, to $3.3 billion compared to $2.6 billion for Q1-05. Operating income for Q1-06 increased by 17% to $194 million compared to $165 million for Q1-05. Gross operating margin increased by 14% to a record $313 million for Q1-06 from $275 million for Q1-05. EBITDA for Q1-06 increased by 13% to a record $301 million from $266 million for Q1-05. Organic growth projects: The Constitution oil and gas pipelines were completed and placed in service during Q1. The San Juan optimization project and the 15,000 BPD expansion of the partnership's NGL fractionator in Mont Belvieu were also completed since the first of the year. The Independence Hub and Trail project was expanded to one billion cubic feet per day during Q1 due to additional offshore discoveries in the eastern Gulf and the project is on budget and on schedule with an expected in service date in Q1-07. EPD announced long-term agreements to construct new processing plants in the fast growing Jonah/Pinedale fields and Piceance basin that extend EPD's integrated NGL value chain in the Rocky Mountains. EPD announced the expansion of our propylene splitter at the Mont Belvieu complex. These projects should support future distribution increases. NGL Pipelines & Services -- Gross operating margin for this segment increased by 12% to $171 million in Q1-06 from $153 million in Q1-05. This increase was primarily due to EPD's NGL pipeline and storage business, which had a 35% increase in gross operating margin to $70 million in Q1-06 compared to $52 million for Q1-05. The increase was largely attributable to record volumes through our NGL export terminal on the Houston Ship Channel; increased volume on the Lou-Tex NGL pipeline; higher volumes and fees at our NGL storage facilities including the assets acquired from Ferrellgas in 2005; and consolidating the Dixie pipeline for a full quarter. Pipeline volumes for Q1-06 were 1,421,000 BPD compared to 1,410,000 BPD in Q1-05. Highlighting the sector's gross operating margin increase: the Texas intrastate pipeline system was up 22%, the San Juan gathering system was up 13% and the Permian Basin gathering systems were up 36% compared to Q1-05. Natural gas processing and related marketing business recorded gross operating margin of $85 million in Q1-06 compared to $84 million in Q1-05. Equity NGL production for Q1-06 was 58,000 BPD compared to 85,000 BPD in Q1-05. Fee-based natural gas processing volumes decreased to 1.8 Bcfd from 2.0 Bcfd in Q1-05. The decrease in volumes was primarily due to the lingering effects of the hurricanes on offshore production. Gross operating margin for Q1-06 included a $4 million recovery from business interruption insurance related to Hurricane Ivan. Gross operating margin from the NGL fractionation business decreased slightly to $16 million for Q1-06 from $18 million in Q1-05. NGL fractionation volumes decreased by 83,000 BPD to 255,000 BPD principally as a result of our Norco, Louisiana facility being idle for most of Q1-06 as a result of a decrease in NGL volumes available for fractionation due to the effects of Hurricanes Katrina and Rita. The decline in gross operating margin was attributable to this decrease in volumes which more than offset the benefit from a $4 million recovery from business interruption insurance with respect to Hurricane Ivan. Enterprise's Norco facility returned to service at the end of March. Onshore Natural Gas Pipelines & Services gross operating margin in Q1-06 increased by 22% to $97 million from $79 million in Q1-05. Enterprise's Texas Intrastate pipelines experienced a 5% increase in volumes to 3.5 trillion BTUs per day on continued drilling in the Barnett Shale and in South Texas. The San Juan basin gathering system completed a record 109 new well connects during Q1 and benefited from higher margins on its percentage of index gathering agreements. The Permian basin gathering and Acadian pipeline systems each turned in a strong quarter based on higher volumes. Total onshore natural gas pipeline volumes increased to approximately 6.1 TBtud during Q1-06 compared to 5.7 TBtud for Q1-05. Offshore Pipelines & Services -- Gross operating margin was $17 million in Q1-06 compared to $23 million in Q1-05. Gross operating margin for Q1-06 included a $2 million recovery on business interruption insurance related to Hurricane Ivan. Offshore natural gas pipeline volumes were down 20% to 1.5 TBTU per day and offshore crude oil transportation volumes were down 10% to 113,000 BPD as a result of the effects of Hurricanes Katrina and Rita. Importantly, the Constitution oil and gas pipelines were placed in service in February and are currently transporting approximately 30,000 BPD and 35 billion BTUs per day. Additionally, the Phoenix gas gathering system, which had been shut in since last year due to damage on a downstream pipeline, was returned to service in April and should return to pre-storm volume levels in Q2-06. Petrochemical Services -- Gross operating margin in Q1-06 increased 42% to $28 million vs. $19 million in Q1-05. EPD's propylene fractionation and pipeline business earned $21 million of gross operating margin in Q1-06 versus $15 million in Q1-05, an increase of $6 million or 38%. Enterprise's butane isomerization business reported a 34% increase in gross operating margin to $18 million in Q1-06 compared to $14 million in Q1-05 as a result of a 27% increase in volume. EPD's octane enhancement facility was idle for most of Q1-06 for its annual turnaround and maintenance program, which is typically scheduled during quarters when demand for motor gasoline and additives is not at peak levels. This business recorded a loss in gross operating margin of approximately $11 million compared to a loss of $9 million for Q1-05. Capitalization -- Total debt outstanding was approximately $4.4 billion. Debt to total capitalization decreased from 45.5% at the end of 2005 to 41.6% on March 31, 2006. Total capital spending in Q1-06 was $305 million, which includes $30 million of sustaining capital expenditures. At the end of the first quarter of 2006, Enterprise had total liquidity of approximately $1.2 billion, which includes availability under EPD's $1.25 billion credit facility and unrestricted cash. My Notes from EPD's Conference Call Josh Lavine asked about the new ethanol mandate - and wanted verification that ethanol must be shipped in dedicated pipelines. EPD: Right now ethanal is moved by train and truck. Ethanol is distributed mainly in the midwest - and it is EPD's opinion that consumption in that area is best serviced by truck. EPD noted that it is selling NGL products to ethanol producers. Yvess Segal from Wachovia - can you review dynamics on Gulf Coast - and where do you stand in talks with Williams? EPD: There is growing production in N Africa - producers want to lock-up storeage. EPD has signed four long term contracts - negotiating 3 more for storage. In Q1 - with a cooler Europe - we exported more and we imported. Mid-America vs Williams project - we are in negotiation with shippers. We are bullish about phase one expansion and may expand more. We are discussing long term contracts. Williams is in talks with us, they announced a new project during these discussions, and that COULD be only a negotiating tactic. Right now Williams takes their gas to Kansas. EPD has a better system to take NGL to better markets - a plan/system that has more flexability and more support services and more storage. If Williams goes with us, we will expand our system nominally 12% - a returns on this expansion should be 12%. If Williams does not go with EPD's pipes, then fine . . we have other organic projects with as good - if not better - returns. Dennis Coleman of Banc of America inquired about insurance costs - saying that he has heard that post Katrina rates are higher. EPD: Major insurures had major losses in 2005 - and insurance prices for offshore properties are up. But increased insurance rates will not be material to EPD results. While EPD will not self-insure, we are always changing our deductables. Mark Easterbrook from RBC asked about insurance claims coming in the rest of the year - how much money is yet to come? EPD: Some will fall into 2007 - as an example, EPD is still collecting on 2004's Ivan. The claims are big numbers - but we can not predict now how much or when the money will come. Paul Snagee asked about the projections that the hurricane season will be bad this year. Is EPD beter organized this time? And what about the 'political threat' on MLPs [on changes in taxation of MLPs]? From operating standpoint - we learned a lot in 2005 from the hurricane experience. In 2005, we moved people and had equipment ready for a quick bounce-back. We are prepped for hurricanes. There is no major construction in the Gulf for EPD during bulk of hurricane season. And we will have product from other parts of the country ready to move if hurricane shuts us down. Concerning politics, there are election year issues - and lots of noise - the price of gas is causing noise. There are some small E&P [exploration and production] MLPs. But the last thing gov't should want to do is interfear. We do not expect any movement to change taxes on MLPs. Unit holders are retirees - politicians do not want to hurt them. Capital is effectivly being raised and put to work in MLPs. And there has been more instituional demand for MLP investments - and this is probably due to the performance/returns in sector. Duncan [or at least an older voice] commented that most of the damages from the hurricanes were not done by winds [but by anchors being dragged across the pipes]. And it was not damage to the offshore pipes that slowed any gas movement, but damage to on-shore pipes that hurt the post-hurricane movement of gas. EPD noted that at 888-566-0078 the replay of the CC will be available through the 2nd of May. Getting Gas to Markets Takes a Pipeline Elizabeth Souder, Dallas Morning News 3-30 A natural gas well without a pipeline is like a car without gas, a chainsaw without a power cord, a bottle of wine without a corkscrew. Without pipelines, the gas can't get to the households of paying customers. That's why, as production of the North Texas Barnett Shale gas field has increased during the last few years, pipelines have proliferated. North Texas is becoming a supplier of natural gas, rather than a consumer, requiring a whole new pipeline infrastructure to carry gas to the richest markets. "If you look at the pipeline network in Texas, it's being challenged to operate in a way it's never operated before," said Kelcy Warren, chief executive of Energy Transfer Partners LP, a Dallas pipeline company. "We have more gas than we have consumption," Warren said. "Where is the next big area of consumption? The Northeast. That is the trophy." At this point, North Texas pipeline companies have laid 1,000s of miles of pipe, enough to give some producers choices about where in the country to send the gas and how to get it there. And still, pipeline experts say, producers will need more pipe to supply the big demand areas on the East Coast. "It's a bottleneck. It's a constraining factor in production in North Texas," said Adam Haynes, director of public affairs for the Texas Independent Producers and Royalty Owners Association. The Barnett Shale field contributes more than 2% of total U.S. natural gas production, according to Pickering Energy Partners. A few years ago, the field produced only a tiny stream of gas for one experimental producer. To move that natural gas to market, pipeline companies have been investing millions of dollars to lay pipe. In the last year, they've built more than 1,000 miles of new pipe in North Texas. Energy Transfer's net income more than tripled in fiscal 2005. From the well, natural gas moves through small gathering lines to a processing center. The gas then travels through an intrastate pipeline either to a customer in Texas or to a market hub, where the gas enters a large interstate pipeline and heads for customers across the country. Natural gas can fetch a better price outside of Texas. Prices in New York can be 35 cents to $2 more than prices in Texas, experts say. That differential has led to stiff competition among companies that lay the pipes in Texas that connect to giant interstate lines. On April 1, Crosstex Energy will start using its new 110-mile, $115 million North Texas pipeline, which connects Tarrant County to an interstate line that runs to Chicago. Think of it as the day a small town gets its own exit on the interstate highway. The Dallas company took two busloads of employees on a tour of the new pipeline in early March, just before the steel tube was buried underground. The office workers took photos of welders connecting the pipes and posed for a group photo with company executives. "It's really driven by the development of reserves in new places today," said Barry Davis, chief executive of Crosstex. Kinder Morgan Energy Partners operates the interstate line that will take the Crosstex feed, and the company will add some pipe to accommodate North Texas producers. North Texas is just one new production area that Kinder Morgan is laying pipe to serve. The Houston pipeline company is also building a pipeline to connect Rocky Mountain natural gas fields to customers in the Midwest. A similar chain of events is happening for Crosstex's Dallas rival, Energy Transfer Partners. Energy Transfer is building an even larger pipeline from Cleburne, Texas, to Carthage, Texas, where it will meet two big interstate pipelines, which are beefing up capacity for the Barnett Shale gas. Energy Transfer executives say the need for pipeline out of North Texas is so great, they may even build their own big interstate line, linking Barnett Shale producers directly with East Coast customers. Warren, the chief executive, said he's hesitated to build his own interstate line because of one major hurdle: federal regulation. In Texas, pipelines are regulated by the Texas Railroad Commission, which Warren described as business-friendly. To build across state lines involves getting permits from the Federal Energy Regulatory Commission, and that can take much longer, he said. Another difference is that federal regulation requires interstate pipelines to auction off capacity to the highest bidders, so the pipeline fees are public knowledge. Texas pipelines don't have to disclose the prices they charge in contracts with gas producers. That's a point of frustration among some producers, who have complained to state policymakers that the lack of transparent pricing information allows some pipeline companies to hold a monopoly in areas with sparse production. If producers have no other pipeline option and they don't know how much other producers are paying to use the pipeline, they have almost no negotiating power. Producers in that situation say their choices are to take any deal the pipeline company offers or not produce at all. Haynes, of the independent producers' organization, said competition among pipelines has increased, but not enough for all producers to get fair rates. "To a large degree, that area has been underserved by pipeline access for producers. As a result, we pay more fees to get that gas to market and sell that gas," he said. Most large producers, such as Chief Oil and Gas LLC, build their own gathering lines to take gas from the wells to an intrastate line. Still, large producers have been constrained by the direction that the intrastate lines go. "The capacity is not sufficient from Texas to move everything all the way East," said Stephen Haywood, Chief's vice president of midstream and marketing. And Jim Dean, head of strategy for Infinity Energy Resources Inc., which produces natural gas on the western frontier of the Barnett Shale, said he can only move his gas west at this point. He's just grateful to have a pipeline close enough to handle his volume. "Those who have the infrastructure have the advantage, clearly," he said, adding that lack of pipeline in the newer production areas of North Texas has slowed down his competitors. He said Infinity, which owns its own gathering system, tried to buy a pipeline in the region but couldn't convince the owner to sell. New Pipeline will Link D-FW Area with Eastern U.S. Dan Piller, Fort Worth Star-Telegram 3-28 Next month's opening of a 140-mile pipeline from near Haslet in northwest Tarrant County to Paris in Northeast Texas can be likened to opening a multilane interstate around a growing suburb. The $155 million pipeline, being built by Crosstex Energy Services, will loop around the north side of Denton and the Dallas-Fort Worth area. Some of the gas will be siphoned to Atmos Energy and other users in the Metroplex. The remainder will flow into interstate pipelines near Paris for shipment to markets in the eastern United States. For the first time, the 90-plus exploration and development companies plying the Barnett Shale will be directly connected to the country's largest consumer markets. Until very recently, the only pipeline outlet for Barnett Shale gas was the old TXU pipeline that ran eastward to serve Dallas. For all the hype about production in the Barnett Shale, which has doubled since 2002 and totaled 455 billion cubic feet last year, the crucial infrastructure to get the gas to market has come slower. Much of the Barnett Shale production has been shut in completed wells because of a lack of pipeline outlets. So the 375 million cubic feet of transport capacity is a needed improvement to aid development of the field and to get the gas to market quickly. Because the number of drilling rigs in the Barnett Shale more than doubled by the end of 2005 to an average of 140 and is likely to increase this year, new production is likely to increase in 2006. Sometime this year, the Barnett Shale will yield its 2 trillionth cubic foot of gas since the field was opened in the late 1990s. Add the Crosstex line to a new pipeline that Energy Transfer Partners of Dallas opened last year from Cleburne to a processing plant at Springtown, and another running east from Cleburne to Carthage in East Texas, and the Barnett Shale field will be looped by pipeline infrastructure by the end of this year. The current configuration, where Barnett Shale gas would have to be piped to Katy, near Houston, to get to East Coast markets, would soon be inadequate for the huge volumes of gas coming out of the Barnett Shale. Also, producers and pipeline people are aware that beginning later this decade, the Gulf Coast will begin receiving liquefied natural gas from foreign sources. The LNG will be added to a pipeline infrastructure along the Gulf that also receives the natural gas produced from offshore rigs. There will be a very tight pipeline situation along the Gulf when LNG shipments begin. Since October, Crosstex's contractors have been laying pipe in 80-foot sections at least 3 1/2 feet below ground. The biggest logistical challenge was the crossing 40 feet under the Trinity River northeast of Denton, which required a 40-foot deep tunnel extending almost 3,000 feet. The principal supplier of natural gas for Crosstex will be Chief Oil & Gas, the Dallas-based operator that last year produced 38 billion cubic feet of gas and whose processing plant near Haslet will be the western terminus of the Crosstex line. Chief has put itself up for sale. "The buyer for Chief will need pipeline access just like anybody else," said Barry Davis, co-founder and president of Crosstex. "And we anticipate that the new owner will, in all likelihood, increase production from Chief leases. So we'll probably get more volumes." So confident is Crosstex in the power of the Barnett Shale that it is already planning a 36-mile expansion of the pipeline extending south from Haslet along the Tarrant/Parker county line to Johnson County. "The lines into the Springtown processing plant are full, so there is a need for more capacity west of Fort Worth," Davis said. The new lines by Crosstex and Energy Transfer Partners, welcome as they are, have renewed long-held suspicions between producers and pipeline operators over pipeline rates. Traditionally, pipeline rates have been confidential, which generates suspicion among producers that some get better deals than others. The Texas Independent Producers and Royalty Owners Association has petitioned the Texas Railroad Commission to make all gas pipeline rates open for public inspection. The association said it is seeking relief from what it calls "monopolistic" practices by pipeline companies, adding "TIPRO is of the opinion that information transparency is necessary for the existence of a competitive environment." Davis acknowledged the issue but said "there is competition among the pipeline companies. We have to knock on doors to get the business. What we're trying to do is help the producers, and I think most of them realize that." Crosstex was born from a buyout by Davis and other executives of the old Comstock pipeline company. Davis and his partners recognized that the deregulation of natural gas pipelines in the 1990s created a niche. "Before deregulation, you had your local gathering lines from the producers and into the users, and the big interstate hubs," Davis said. "But deregulation created the need for a midlevel niche of pipelines that serve intrastate markets." Highlights from the Annual Bentek Report Gas Processors Report 4-05 Continental U.S. production is dramatically responding to current high prices. Total U.S. (excluding Alaska) gross withdrawals declined by 0.2% over 2004, but this includes some 572 Bcf cumulative losses associated with hurricanes Katrina, Rita and Wilma. Were it not for the hurricanes, production would have increased by 2.7% over 2004. Basins having the greatest increases are Fort Worth (17%), Uinta-Piceance [in Colorado and Utah] (16%), East Texas (11%), Arkla (10%), Raton [northeastern New Mexico and southeastern Colorado ] (9%) and Wind River [Wyoming] (6%). The Offshore Gulf (-18%), Denver Julesburg [northeast Colorado] (-3%) and Powder River [northeast Wyoming ] (-3%) are the basins that had the largest production declines. Production gains in the West and East Texas basins will alter historical flow patterns in the U.S., requiring additional infrastructure investments to alleviate bottlenecks. U.S. total supply, including production, imports and storage withdrawals was up by 0.1% in 2005 compared to 2004. Total demand, including consumption, storage injections, exports and line losses, increased by 0.5%. Total Continental U.S. consumption by end users - residential, commercial, industrial and power generators - increased by 2.2%. Consumption rose 3% in the Northeast, 4% in the Southeast, 2% in the Midwest and in Texas and was unchanged in the West. 2005 began with prices at Henry Hub equal to $6.25/mmbtu and ended at $10.54. Prices soared higher in between, with many historic highs. High product prices stimulated production. According to Baker Hughes, there were an average of 1,383 rigs operating during the year, the highest number since 1985; and this activity in many producing regions translated to increased production. Even the offshore Gulf areas saw production make slow gains until the end of August and the arrival of Hurricane Katrina. The Gulf Offshore and Louisiana Onshore basins are large supply sources for Midwest and Northeastern and Southeastern markets. While some of the basins that serve the Midwest, Northeast and Southeast markets experienced gains (Fort Worth, East Texas and Texas Gulf Coast for example), because of the large offshore declines, the net impact was that these market areas had less volume available from their traditional source basins. Moreover, the Fort Worth, East Texas and Arkla basins are increasing in volume relative to the Gulf Offshore and Louisiana Gulf Coast. The pipelines that carry gas from the Gulf to Midwest and Northeast markets telescope; their capacity generally shrinks as they move north. But production growth to the north of the Gulf of Mexico is getting squeezed by the smaller capacity of the pipelines in those areas. Growth in Fort Worth, East Texas and Arkla production has already created capacity bottlenecks, and numerous pipeline projects have been announced to alleviate this situation. However, should the Gulf declines reverse or LNG imports grow as planned, the combination may create new bottlenecks in the area. In the West, the picture is entirely different. Basins that primarily serve local or western markets had a net gain of 360 Bcf or 986 MMcfd. Total Western demand grew by only 44 million cfd, so an additional 942 million cfd was available for export to the Midwest. The amount of economical, ready-to-capture gas - under existing wells within reach of pipelines - rose 15% during the four years ending in 2004, according to the latest federal data. The American Gas Association, a group of utilities, has made a preliminary estimate of another 4% rise last year. (Jeff Dinna, AP 4-29) Gas-fired generators [used] almost 1 trillion more cubic feet of natural gas last year than in 1999. But at the same time, factories cut back, using almost 1.5 trillion less, federal data show. (Jeff Dinna, AP 4-29) Ten years ago, says Doug Rachlin, who manages $300m in an MLP portfolio at Neuberger Berman, there were 15 oil and gas MLPs with a market value of $10bn. Today there are 50 worth more than $70 billion. Between 1990 and 2004, this asset class returned 16% [annualised] and is showing no signs of slowing down. "Less than 25% of companies capable of being an MLP are one. There's a lot of room for growth" says Joseph Grunfeld, private wealth advisor at Merrill Lynch. (Paul Sullivan, FTWealth 4-21) John Tysseland, director of MLP research at Citigroup, notes that last year total returns ranged from negative 20% to plus 40% - averaging out at 6.3%. Tysseland adds: "We believe picking individual MLPs is going to be very important for performance." His favourites are those that are growing internally and not through acquisition. His reasoning is that the acquisition multiples are too high now compared with five years ago, when energy companies were selling pipeline assets. "We see 12% - 20% for organic growth returns against acquisition returns in the 8% - 10% range," he says, recommending companies such as Enterprise Products, Magellan Midstream, Plains All American, Boardwalk Partners and Energy Transfer. (Paul Sullivan, FTWealth 4-21) On the fringes, there are other MLPs that may appeal to people with a quirkier investment sense. Cedar Fair operates a chain of amusement parks. Stonemor Partners owns 155 cemeteries and 14 funeral homes in 14 states, with revenues totalling $100m, and it became an MLP in September 2004. Macadamia Orchards offers exposure to nuts, while Equus Gaming owns horse tracks. But with only about a dozen non-pipeline MLPs, investors need to evaluate them as individual securities. (Paul Sullivan, FTWealth 4-21) During Q1-06 MLP equity offerings totaled $2.2 billion, compared to $0.9 billion in Q1-05. (John Tysseland, CitiGroup 4-10) On 4-05, Wachovia Initiated coverage of XTEX at Outperform. On 4-20 Citigroup Downgraded KMP from Buy to Hold. On 4-24 Citigroup Upgraded SXL from Hold to Buy. On 4-25 Deutsche Securities Upgraded VLI from Hold to Buy. Enterprise GP Holdings Increases Distribution Businesswire 4-17 Enterprise GP Holdings [EPE] announced its quarterly cash distribution to partners of $0.295 per common unit, or $1.18 per common unit on an annual basis. This distribution represents a 5.4% increase over the $0.28 per unit quarterly distribution paid with respect to Q4-05 and an 18% increase over the $0.25 per unit expected initial quarterly distribution as stated in the prospectus dated August 23, 2005. Energy Transfer Equity Reports Q2 Results Businesswire 4-17 Energy Transfer Equity reported net income for Q2 ended February 28, 2006 of $24.4 million, as compared to net income of $38.8 million forQ2-05, a decrease of $14.4 million. EBITDA, as adjusted, for Q2-06 was $151.5 million versus the $95.9 million In Q2-05, an increase of $55.6 million or approximately 58%. For the six months ended February 28, 2006, net income increased $10.8 million or about 20% to $64.0 million as compared to $53.2 million for the six months ended February 28, 2005. EBITDA, as adjusted, increased $129.6 million or about 87% to $278.6 million for the six months ended February 28, 2006 as compared to $149.0 million for the six months ended February 28, 2005. Net income for the three and six month periods ended February 28, 2006 was affected by a $109.5 million and $166.1 million increase, respectively, in minority interest expense, which is attributable to the increase in income from Energy Transfer Partners, L.P. The minority interest expense primarily represents partnership interests in Energy Transfer Partners, L.P. that the Partnership does not own. Net income for the three and six months ended February 28, 2006 was also affected by a non-cash expense of $52.9 million related to the issuance of the Partnership's Class B Units at the time of the Partnership's initial public offering in February 2006. Crosstex Increases Distribution PRNewswire 4-21 Crosstex Energy, Inc. quarterly dividend will increase from $0.56 per share to $0.60 per share, payable May 15. Magellan Increases Distribution PRNewswire 4-26 Magellan Midstream Holdings [MGG] declared its initial quarterly cash distribution of 20.8 cents per unit for the period Jan. 1 through March 31, 2006, or 83.2 cents on an annual basis. The announced quarterly distribution represents a 6.7% increase from the expected quarterly distribution rate of 19.5 cents, or 78 cents on an annual basis, stated in the partnership's initial public "This 6.7% distribution increase versus the expected initial quarterly distribution included in our IPO prospectus is directly related to the 2.3% distribution increase by Magellan Midstream Partners, L.P. for first-quarter 2006 versus fourth-quarter 2005," said John Chandler, chief financial officer. |