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For March month to date [throught the 31st], 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. The most opportunistic times to buy have been when spreads were over 190. Fortunately for the sector, we are close to April's announcements of distribution increases. After having said that the sinking spread should be a warning, I should also note that there is little reason for those REITs which are growing dividends at 8-10% per year should sell at a 3% yield while MLPs that are growing distributions at the same pace sell at 6% yields. So the 'rule of the 190 spread' could quickly change. Three of the six double-diget price gainers in this sector so far in 2006 have been rookies or near rookies [BWP, CPNO and HLND]. So keeping an eye out for attractive upcoming IPOs is one way to generate above sector average returns. I added an article on 3-23 [toward the bottom of this page - "LNG Companies Mull Conversion to MLPs"] on specualation of upcoming MLP IPOs from established LNG companies - which include Southern Union, El Paso, Sempra Energy, Suez, Dominion Resources and Cheniere Energy. Friday afternoon [3-31] I updated the EPS estimates. There were large estimate increases for APL, CPNO, ETP, NBP and TPL - and large decreases for MWE and XTEX. It is probably not a coincidence that the large changes came mostly in those MLPs reporting earnings in March. DCF estimates for two of the three brokerages were updated on 3-20. The composite DCF estimates were also updated. Estimates for NBP were up big, but other changes were small. I have yet to begin tracking expected Q2 distributions, so ETP [which is the only MLP that has announced a Q2 distribution increase] along with CEF's FEN, KYE and KYN, are not listed at their 'forward' yield. BWP has a correct forward yield, but it only paid a partial distribution in Q1, and that is NOT reflected in its year to date return - which is overstated. Distribution History has been updated based on Q1 year-over-year growth. This site will begin tracking selected valuations for GP's [ETE, EPE, MGG, MWP & XTXI] when Yahoo produces EPS estimates for the newest members. Currently there are no EPS estimates for ETE, MGG and MWP. The same three lack price targets. ETE and MGG have yet to have a dividend - so yields can not yet be calculated. So given the lack of metrics available, it could be April before stats on GPs begin. For February, the MLP midstream sector was up 0.04%, with pipelines up 0.14%. The sector yielded 6.68% [after correcting or updating the distribution for WPZ], with the average pipeline yielding 6.61% [vs. 6.47% at January's end - up 3 basis points]. With the ten year treasury ending February 4.55%, the MLP midstream spread was at 213 basis points and the pipeline spread was 206. While the pipeline sector was up 4.85% for Janaury, its yield was still up 23 basis points. The total midstream sector was up 4.44% and the yield, at 6.56%, was up 20 basis points. During January, APL, BPL, EPD, ETP [for Q2], HEP, HLND, KMP, MMLP, MMP, PAA, PPX, SXL and XTEX announced distribution increases. 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. The Importance of Distribution/DCF Ratios: It is logical that MLPs that keep more of their distributable cash flows should, due to reinvestment of more self-generating cash, grow their unit price faster than those that keep less. But just because it is logical does not make it true. Below I track the stats on that theory. The following companies had Distribution/DCF ratios of less than 90.6% [the sector average at the begining of the year] : APL , BPL , BWP , CPNO , ETP , HEP , HLND , MWE , NBP , PAA , PPX , SXL , TCLP , TLP , VLI , WPZ , XTEX , MMLP , TGP . Their mean price gain for the year is 8.56%. Their mean total return for the year is 10.26% - and 9 of the 19 beat the sector average yearly price gain [6.67%]. The following companies had Distribution/DCF ratios of more than the sector average of 90.6% : EEP , EPD , KMP , MMP , TPP , KSP , USS . Their mean price gain for the year is 1.53%. Their mean total return for the year is 3.38% - and 0 of the 7 beat the sector average yearly price gain. The Importance of Ratings: Can analysts pick between the MLP winners and the fully valued? Below I track the stats on that theory that the higher rated stocks will outperform the lower rated ones. The following companies were the highest rated MLPs - those that had ratings of less than 2.25 [the sector average at the begining of the year] : APL , BWP , EPD , ETP , HLND , MMP , MWE , PAA , PPX , XTEX , TGP , USS . Their mean price gain for the year is 7.94%. Their mean total return for the year is 9.7% - and 4 of the 12 beat the sector average yearly price gain. The following companies had ratings of more than the sector average of 2.25% : BPL , CPNO , EEP , HEP , KMP , NBP , SXL , TCLP , TLP , TPP , VLI , WPZ , KSP , MMLP . Their mean price gain for the year is 5.58%. Their mean total return for the year is 7.31% - and 5 of the 14 beat the sector average yearly price gain. The Importance of Ratings Part Two: Given that the analysts picks will fall on a bell curve - spliting their MLP picks into only two groups puts similarly rated stocks [the majority that fall in the middle] into two different camps - and this could muddle the results. Below I track the stats on that theory that the highest rated stocks will outperform. The following companies were the highest rated MLPs - those that had ratings of less than 2.0 : APL , EPD , ETP , MMP , PAA , PPX , XTEX , TGP . Their mean price gain for the year is 6.03%. Their mean total return for the year is 7.74% - and 2 of the 8 beat the sector average yearly price gain. The following companies had ratings of more than 2.0 : BPL , BWP , CPNO , EEP , HEP , HLND , KMP , MWE , NBP , SXL , TCLP , TLP , TPP , VLI , WPZ , KSP , MMLP , USS . Their mean price gain for the year is 6.95%. Their mean total return for the year is 8.71% - and 7 of the 18 beat the sector average yearly price gain. The Importance of Yield: MLPs with the lowest yield are priced higher [on a price/distribution basis] due to the expectations that they will grow their unit price. Yield is a 'rating' that investors give a stock. Since yield is a bird in the hand and growth is a bird in the bush, growth should sell at a discount - and growth stocks [the low yielders] should have a superior total return. Below I track the stats on that theory. The following companies had yields of less than 6.92% [the sector average at the begining of the year] : CPNO , ETP , HEP , HLND , KMP , MMP , TLP , VLI , WPZ , XTEX , KSP , TGP . Their mean price gain for the year is 6.97%. Their mean total return for the year is 8.52% - and 5 of the 12 beat the sector average yearly price gain. The following companies had yields of more than the sector average of 6.92% : APL , BPL , BWP , EEP , EPD , MWE , NBP , PAA , PPX , SXL , TCLP , TPP , MMLP , USS . Their mean price gain for the year is 6.41%. Their mean total return for the year is 8.32% - and 4 of the 14 beat the sector average yearly price gain. The Importance of Price Targets: MLPs which sell at the largest discount to their twelve month price target should - if the analyst are correct - out-return those that sell at a smaller disount to target - right? The following companies had price to target ratios of less 84% [the sector average at the begining of the year] : APL , BWP , EEP , EPD , HEP , HLND , MWE , PAA , PPX , VLI , XTEX , MMLP , USS . Their mean price gain for the year is 7.13%. Their mean total return for the year is 8.97% - and 4 of the 13 beat the sector average yearly price gain. The following companies had price to target ratios of more than 84% : BPL , CPNO , ETP , KMP , MMP , NBP , SXL , TCLP , TLP , TPP , WPZ , KSP , TGP . Their mean price gain for the year is 6.21%. Their mean total return for the year is 7.85% - and 5 of the 13 beat the sector average yearly price gain. The Importance of Distribution Increases [Annual]: MLPs which increase their distribution at the fastest pace will out-perform those MLPs that don't - but did they in Q1? The following companies had distribution increases of greater than 10% from Q1-05 to Q1-06 : APL , CPNO , ETP , HEP , MMP , PAA , PPX , SXL , XTEX , MMLP , USS . Their mean price gain for the year is 8.06%. Their mean total return for the year is 9.84% - and 5 of the 11 beat the sector average yearly price gain. The following companies had distribution increases of less than 10% : BPL , EEP , EPD , KMP , MWE , NBP , TCLP , TPP , VLI , KSP . Their mean price gain for the year is 2.2%. Their mean total return for the year is 4% - and 1 of the 10 beat the sector average yearly price gain. High Distribution Increases [in Q1]: MLPs with increasing distributions out-perform, but in this what have you done for me lately world, is short term performance more important? Or are long term trends what matter? The following companies had distribution increases of greater than 3% from Q4-05 to Q1-06 : CPNO , ETP , HEP , HLND , MMP , PPX , SXL , WPZ , XTEX , KSP , MMLP . Their mean price gain for the year is 7.78%. Their mean total return for the year is 9.44% - and 5 of the 11 beat the sector average yearly price gain [6.67%]. The following companies had distribution increases of less than 3% : APL , BPL , EEP , EPD , KMP , MWE , NBP , PAA , TCLP , TLP , TPP , VLI , TGP , USS . Their mean price gain for the year is 4.75%. Their mean total return for the year is 6.54% - and 3 of the 14 beat the sector average yearly price gain. Newbies vs. Old Timers: It is the newer MLPs that have the most favorable GP splits - but is that important? Or are there other attributes that give the veteran MLPs an advantage? The following companies had not yet to begin distributions in Q1-04 [the newer MLPs] : BWP , CPNO , HEP , HLND , TLP , WPZ , KSP , TGP , USS . Their mean price gain for the year is 10.43%. Their mean total return for the year is 12.05% - and 5 of the 9 beat the sector average yearly price gain. The following companies are the veteran MLPs : APL , BPL , EEP , EPD , ETP , KMP , MMP , MWE , NBP , PAA , PPX , SXL , TCLP , TPP , VLI , XTEX , MMLP . Their mean price gain for the year is 4.68%. Their mean total return for the year is 6.49% - and 4 of the 17 beat the sector average yearly price gain. The four veteran MLPs that beat the sector average all had explanations for their Q1 success. ETP continues to grow distributions like no other vet. PAA reported 56% EPS growth in 2005 and predicted 10% distribution growth for the foreseeable future. And both NBP and SXL - down 12.83% and 10.10% in 2005 - were getting a bounce after that sorry year. SXL, which is growing distributions like a winner, began the year yielding well above sector average and had a P/E well below sector average. NBP, after years of no distribution growth, is expected to turn things around in 2006. NBPs 2006 EPS estimate grew over 26% in Q1 alone. It also began the year with a higher yield and lower P/E than sector average. Even after gaining 14% in Q1, it still sells at a Price/2006 Earnings estimate discount - going at 14.70 vs. the sectors 20.39. And NBPs 6.68% March ending yield is still above the pipeline average. If NBP has future growth, then buying it in Q1 was getting growth at a reasonable price. In summary, for a vet MLP to be a winner in Q1, it had to have a strong story behind it. Earnings Growth: The consensus 2007 EPS estimates were first published in Q1 - with an average growth of 16.84% Did those with estimates of higher growth outperform those with below average growth? The following companies had 2007 EPS of greater than 16.84% : CPNO , EPD , HLND , MWE , XTEX , MMLP , TGP , USS . Their mean price gain for the year is 6.97%. Their mean total return for the year is 8.68% - and 2 of the 8 beat the sector average yearly price gain. The following companies had 2007 EPS of less than 16.84% : APL , BPL , BWP , EEP , ETP , HEP , KMP , MMP , NBP , PAA , PPX , SXL , TCLP , TLP , TPP , VLI , WPZ , KSP . Their mean price gain for the year is 6.53%. Their mean total return for the year is 8.29% - and 7 of the 18 beat the sector average yearly price gain. Explaing Price Movements - EPS Estimate Changes The 2006 EPS estimates changed for all but one MLP. Did the 13 having increases outperform the 14 with EPS decreases [or with no change] during the quarter? The following companies had 2006 EPS estimate increases : BWP , CPNO , ETP , NBP , PAA , SXL , TCLP , TLP , WPZ , TGP . Their mean price gain for the year is 11.18%. Their mean total return for the year is 12.81% - and 7 of the 10 beat the sector average yearly price gain. The following companies had 2006 EPS estimate decreases : APL , BPL , EEP , EPD , HEP , HLND , KMP , MMP , MWE , PPX , TPP , VLI , XTEX , KSP , MMLP , USS . Their mean price gain for the year is 3.85%. Their mean total return for the year is 5.67% - and 2 of the 16 beat the sector average yearly price gain. The two companies with falling EPS that beat the sector average - HEP and HLND - were both newbies, with low distribution to DCF ratios. HEP began the year with an above sector average yield. HLND began the year with a well below sector average P/E. Explaing Price Movements - Target Price Changes The price targets changed for all but two MLPs. Did those having increases outperform those with decreases during the quarter? The following companies had price target increases : BWP , CPNO , EPD , ETP , KMP , NBP , PAA , SXL , TCLP , TLP , WPZ , KSP , MMLP , TGP . Their mean price gain for the year is 8.31%. Their mean total return for the year is 9.98% - and 7 of the 14 beat the sector average yearly price gain. The following companies had price target decreases : APL , BPL , EEP , HEP , HLND , MMP , MWE , PPX , TPP , VLI , XTEX , USS . Their mean price gain for the year is 4.76%. Their mean total return for the year is 6.58% - and 2 of the 12 beat the sector average yearly price gain. Williams Partners L.P. Reports Financial Results PRNewswire 3-01 Williams Partners L.P. announced 2005 unaudited net income of $4.8 million, or 44 cents per unit, compared with a net loss of $13.4 million in 2004. For Q4-05, WPZ reported unaudited net income of $5.5 million, or 46 cents per unit, compared with a net loss of $12.2 million during Q4-04. Distributable cash flow for WPZ and its 40% interest in Discovery pipeline totaled $25.4 million in 2005. That amount compares with $23.0 million during 2004. For Q4-05, distributable cash flow was $9.9 million. In Q4-04, distributable cash flow totaled $6.1 million. Adjusted EBITDA for WPZ and its 40% interest in Discovery pipeline totaled $11.0 million for Q4-05, up from $7.6 million for Q4-04. For the full year, adjusted EBITDA totaled $28.5 million, compared with $25.3 million in 2004. For 2005, WPZ's net income of $4.8 million was favorable to the $13.4 million loss in 2004 due primarily to the absence of an impairment of WPZ's investment in Discovery recorded in Q4-04, greater earnings from the WPZ's interest in Discovery, higher storage revenues and lower interest expense. Discovery's increase in earnings included income from a previously deferred system gain and open-season revenue that served to offset the ongoing impact on its traditional revenue base caused by hurricanes Katrina and Rita. Those benefits were offset by increased operating and maintenance expenses and higher general and administrative expenses. "In a year where hurricanes dramatically affected the entire energy industry in the Gulf of Mexico, Williams Partners turned in a strong performance," said Alan Armstrong, COO. "We moved quickly to ensure natural gas stranded by hurricane damage could find a way to market," Armstrong said. "For Williams Partners, those incremental volumes in Q4 moved transportation on the Discovery system up nearly 60% above 2004 levels. We expect most of these volumes ultimately will migrate back to pre-hurricane transportation routes." Discovery has been flowing approximately 412,000 dekatherms per day of incremental volumes as a result of two fully subscribed, expedited open seasons for transportation capacity held last October. One newly constructed receipt point and one reversed interconnection allows for the firm transportation of the volumes that had been stranded as a result of hurricane. Discovery's Larose plant is processing additional volumes. Discovery plans to provide the transportation and processing services associated with the open seasons through the end of Q1-06. Base volumes shipped on Discovery prior to the hurricanes have not yet returned as a result of continued hurricane-related damages. Pre-construction activity progresses on an approximately 35-mile gathering pipeline to connect Discovery's existing pipeline system to certain producers' production facilities for the Tahiti prospect in the deepwater Gulf of Mexico. The Tahiti pipeline lateral expansion, with an expected design capacity of approximately 200 million cubic feet per day, is scheduled to be in service by May 2007. Boardwalk Pipeline Partners Announces $575 Million Pipeline Expansion BusinessWire 3-01 Boardwalk Pipeline Partners announced that its subsidiary, Gulf South Pipeline, has signed long-term binding precedent agreements with customers for capacity on its East Texas and Mississippi expansion projects. These contracts provide firm commitments for the 1.0 Bcf per day pipeline. Total cost for the expansion is expected to be $575 million, and the new capacity is expected to be in-service during the second half of 2007. Boardwalk expects that the projects will contribute approximately $70 million of annual incremental EBITDA. The pipeline capacity may be further expanded depending on the results of ongoing customer discussions. Boardwalk announced on 3-14 that Gulf South had signed long-term binding precedent agreements with customers for additional capacity on its previously announced East Texas and Mississippi expansion projects. These contracts support increasing the capacity of the expansion projects announced on March 1, 2006 from 1.0 Bcf/day to 1.5 Bcf/day. The total cost of the expanded projects is expected to be approximately $800 million, an increase of $225 million from the amount previously announced. Boardwalk expects that the expanded projects will contribute total annual EBITDA of approximately $100 million an increase of $30 million from the amount previously announced. The new capacity is expected to be in service during the second half of 2007. Atlas Pipeline Partners Reports Record Q4 Results Businesswire 3-01 Atlas Pipeline Partners reported record EBITDA of $21.3 million for Q4-05 compared with $14.5 million for Q4-04, an increase of $6.8 million or 47%. Net income for Q4-05 was $10.9 million, or $0.70/unit, compared with $11.1 million for Q4-04, or $1.35/unit. Net income and EBITDA for the fourth quarter 2004 included a $4.4 million non-recurring gain on an arbitration settlement. The period over period increase in EBITDA was principally related to contributions from the acquisitions of a 75% interest in NOARK Pipeline System, Limited Partnership ("NOARK") in October 2005 and ETC Oklahoma Pipeline, Ltd. ("Elk City") in April 2005 and continued growth in the Partnership's Appalachian operations, partially offset by the absence in the current quarter of the gain recognized on the arbitration settlement. Excluding the net gain on arbitration settlement and solely for purposes of comparing Q4-05 to Q4-04, APL's distributable cash flow of $17.5 million for Q4-05 would have represented an increase of $8.6 million, or 97%, compared with adjusted distributable cash flow of $8.9 million for Q4-04. On January 9, 2006, APL declared a record quarterly cash distribution for the fourth quarter 2005 of $0.83 per limited partner unit, paid February 14, 2006 to unitholders of record as of February 7, 2006. Distributions declared for the year ended December 31, 2005 of $3.16 per limited partner unit represent an 18% increase compared with distributions declared per limited partner unit for the year ended December 31, 2004. "Our record Q4 results demonstrate the continued execution of our growth strategies and the commendable performance of our assets," said Edward Cohen, Chairman and CEO of APL's GP. "Our Mid-Continent operations achieved significant growth quarter over quarter due to a substantial contribution from the NOARK system from its date of acquisition and favorable increases in volumes and processing margins at our Elk City system. We expect that our interest in the NOARK system will continue to add meaningfully to our results and provide us with additional expansion opportunities to fuel our growth in the region. Our Appalachia system continues to generate strong returns due to its strategic market position. The sustained growth of our cash flow and prospects for future expansion reinforces our decision to increase our quarterly distribution to $0.83 per limited partner unit, representing a 15% increase over Q4-04 and our seventh consecutive distribution increase." On 12-20-05, APL issued $250.0 million of 10 year, 8.125% senior unsecured notes in a private placement for net proceeds of approximately $243.1 million. APL utilized the net proceeds principally to repay indebtedness under its credit facility. On 11-28-05, APL sold 2,700,000 LP units for gross proceeds of $113.4 million. In addition, pursuant to an option granted to the underwriters of the offering, APL sold 330,000 limited partner units on 12-27-05 for gross proceeds of $13.9 million, or aggregate total gross proceeds of $127.3 million. The sale of the units resulted in net proceeds of approximately $121.0 million. APL primarily utilized the net proceeds to repay a portion of the amounts due under its credit facility. On 10-31-05, APL acquired all of the outstanding equity interests in a subsidiary of OGE Energy, which owns a 75% operating interest in NOARK. NOARK's assets include a FERC-regulated interstate pipeline and an unregulated natural gas gathering system. Total consideration of $179.8 million, including $16.8 million for working capital adjustments and other related transaction costs, was funded through borrowings under APL's amended credit facility. The remaining 25% interest in NOARK is owned by Southwestern Energy Pipeline Company. The Mid-Continent segment, which was initiated upon the acquisition of the Velma system assets in July 2004 and expanded with the acquisitions of the Elk City system assets and the 75% interest in NOARK, recognized total revenue of $128.3 million for the fourth quarter 2005, an increase of $86.2 million from the fourth quarter 2004. This increase principally reflects the contributions from the acquisitions of the 75% interest in NOARK and the Elk City system, higher volumes at the Velma system and an increase in commodity prices. Velma's gross natural gas gathered volume averaged 61.1 million cubic feet per day ("MMcfd") for Q4-05, an increase of 6.8% from Q4-04. The Velma system connected 10 new wells to its gas gathering system for Q4-05; overall, 63 new wells were connected to the Velma system for the year 2005 compared with 66 new wells connected from its date of acquisition to 12-31-04. For the Elk City system, gross natural gas gathered volume averaged 266.3 MMcfd, and 16 new wells were connected to the system for the fourth quarter 2005, or 42 new wells since its date of acquisition. For the NOARK system, average throughput volume was 255.8 MMcfd from 10-31-05, its date of acquisition, to 12-31-05. The segmented Mid-Continent results include the consolidated financial statements of NOARK. Minority interest in NOARK represents Southwestern's 25% ownership interest in the net income of NOARK and is classified within costs and expenses within the consolidated statements of income. Total revenue for the Appalachia system increased to $8.0 million for Q4-05, a 45% increase from $5.5 million for Q4-04. For Q4-05, Appalachia segment profit was $5.6 million, or 33% of total segment operating profit for the period, compared with $3.8 million, or 45% of total segment operating profit for Q4-04. Average transportation rate per thousand cubic feet ("mcf") rose to $1.53 for Q4-05 from $1.08 for Q4-04 due mainly to the rise in natural gas prices. Throughput volume increased to 56.4 MMcfd for Q4-05 compared with 55.1 MMcfd for Q4-04. The Partnership has recently completed two major transmission line connections and is in the process of completing a third connection that will result in substantial additional natural gas volume to be transported through its Appalachia system. APL estimates that there are approximately 270 wells that were awaiting completion of these expansion projects. During Q4-05, 91 new wells were connected to the gathering system. Overall, 451 new wells were connected to the system for 2005 compared with 352 wells connected for 2004. General and administrative expenses, including amounts reimbursed to affiliates, increased $2.7 million to $4.5 million for the fourth quarter 2005 from $1.8 million for Q4-04. This increase was primarily related to general and administrative expenses associated with the operations of the acquired assets in the Mid-Continent region and a $1.5 million increase in non-cash compensation expense related to vesting of incentive awards. Depreciation and amortization increased $3.1 million to $5.5 million for Q4-05 due principally to the depreciation and amortization of the assets acquired. Interest expense increased to $5.7 million for Q4-05, an increase of $4.6 million from the prior year fourth quarter. This increase was primarily related to interest associated with the borrowings under the credit facility used to finance the acquired assets. At December 31, 2005, there was $9.5 million of outstanding borrowings under the credit facility as the majority of the borrowings associated with the acquired assets were repaid with the net proceeds from the Partnership's November 2005 equity offering and December 2005 issuance of $250.0 million of senior unsecured notes. TransMontaigne Announces Results for Q4-05 Businesswire 3-02 TransMontaigne Partners L.P. today announced its net earnings allocable to limited partners of $3.5 million ($0.48 per limited partner unit) for the quarter ended December 31, 2005. The quarter's highlights include: [1] Quarterly revenues increased to $11.1 million from $8.3 million last year; [2] Quarterly operating income increased to $4.1 million from $2.0 million last year; [3] Adjusted operating surplus generated during the period was $5.0 million; and [4] TLP declared a $0.40 per unit minimum quarterly distribution for the period. Quarterly throughput volumes increased from 123,200 barrels per day in 2004 to 139,200 barrels per day in 2005. This volume increase, combined with new third-party storage customers and other revenues, resulted in an increase in operating income from $2.0 million in 2004 to $4.1 million in 2005. Copano Reports Record Q4 Results PRnewswire 3-06 Revenue for Q4-05 increased approximately 145% to $295.1 million from $120.3 million in Q4-04. Total gross margin increased from $17.5 million in Q4-04 to $45.7 million in Q4-05. Net income was $14.3 million, or $0.84/unit, for Q4-05 compared to a net loss of $2.4 million, or $0.39/unit for Q4-04. The weighted average diluted units outstanding during the three months ended December 31, 2005 and 2004 totaled approximately 16.9 million and 6.1 million, respectively. EBITDA for Q4-05 were $31.9 million, an increase of $20.9 million from EBITDA of $11.0 million for Q4-04. Distributable cash flow for Q4-05 (prior to any retained cash reserves established by Copano's board) equaled $22.6 million, representing 224% coverage of the increased Q4-05 distribution of $0.55 per unit based on the number of units outstanding on 2-1-06, the Q4 distribution record date. Revenue for the year ended December 31, 2005 increased approximately 71% to $747.7 million from $437.7 million last year. Total gross margin increased from $51.5 million in 2004 to $104.1 million in 2005. EBITDA for 2005 was $67.9 million, an increase of $38.4 million from EBITDA of $29.5 million for 2004. Net income was $30.4 million, or $2.29 per unit on a diluted basis, for 2005 compared to a net loss of $0.9 million, or $0.35 per equivalent unit on a diluted basis, for the same period last year. The weighted average diluted units outstanding during the year ended December 31, 2005 and 2004 totaled approximately 13.3 million and 2.6 million (equivalent units), respectively. Texas Gulf Coast Pipelines is comprised of a series of gathering and intrastate transmission systems totaling 1,396 miles of natural gas pipelines, which include 144 miles of pipelines owned by Webb/Duval Gatherers, an unconsolidated general partnership in which Copano owns a 62.5% interest. During Q4-05, the Texas Gulf Coast Pipelines segment gathered or transported an average of 355,181 MMBtu/d of natural gas on its pipelines, which included 238,602 MMBtu/d of natural gas on its wholly owned pipelines and 116,579 MMBtu/d on the Webb/Duval Gathering System, net of intercompany volumes. During Q4-04, this segment gathered and transported an average of 351,376 MMBtu/d of natural gas on its pipelines, which included 232,723 MMBtu/d of natural gas on its wholly owned pipelines and 118,653 MMBtu/d of natural gas on the Webb/Duval Gathering System, net of intercompany volumes. Gross margin for this segment in Q4-05 increased approximately 9% to $9.5 million compared to $8.7 million in Q4-04. The increase primarily resulted from higher average natural gas prices during the fourth quarter of 2005, which caused an increase in margins associated with Texas Gulf Coast Pipelines' index price-related gas purchase and transportation arrangements. Texas Gulf Coast Processing includes the Houston Central Processing Plant and the Sheridan NGL pipeline that extends from the tailgate of the processing plant to the Houston area. During Q4-05, the Texas Gulf Coast Processing segment processed an average of 559,532 MMBtu/d of natural gas, a 2.5% increase, compared to 545,742 MMBtu/d during Q4-04. For the same period, the Houston Central Processing Plant produced an average of 11,064 barrels per day of natural gas liquids, or NGLs, compared to an average of 16,004 barrels per day during Q4-04. Gross margin for the Texas Gulf Coast Processing segment in Q4-05 increased to $9.7 million compared to $8.8 million in Q4-04. The increase in gross margin primarily resulted from higher NGL prices and Copano's use of its conditioning option to take advantage of market opportunities. This increase was partially offset by higher natural gas prices. On August 1, 2005, Copano completed its acquisition of Tulsa-based ScissorTail Energy, LLC, a provider of natural gas midstream services in central and eastern Oklahoma. ScissorTail's assets, which we refer to as our Mid-Continent Operations segment, include 3,331 miles of gathering pipelines and three processing plants. During the fourth quarter of 2005, gross margin for this segment totaled $25.8 million and the Mid-Continent Operations segment gathered or transported an average of 160,443 MMBtu/d of natural gas on its pipelines, processed an average of 109,149 MMBtu/d of natural gas and produced an average of 9,421 barrels per day of NGLs. For Q4-04, the Mid-Continent Operations segment gathered or transported an average of 138,159 MMBtu/d of natural gas on its pipelines, processed an average of 93,250 MMBtu/d of natural gas and produced an average of 7,927 barrels per day of NGLs. Energy Transfer Increases Q2 Distribution - Again Businesswire 3-08 In a January 26, 2006 press release, ETP announced management's recommendation to increase its distribution by $0.10 per unit on an annualized basis. Based upon ETP's continuing improved performance, management has recommended, and the Board of Directors of the Partnership's general partner has approved, an increase of $0.15 per unit, representing an annualized distribution of $2.35 per unit. This increase is the eighteenth increase since going public, and represents a 6.8% increase from the prior quarter's distribution. On 3-10, Energy Transfer Equity [EPE] announced that the Board of Directors of its general partner has declared its initial quarterly cash distribution to be $.20, for the fiscal quarter ended February 28, 2006. The Board of Directors increased the Partnership's annual distribution rate to $0.80 per year ($0.20 per quarter), which increased rate is 14.3% higher than the expected initial annual distribution rate of $0.70 per year ($0.175 on a quarterly basis), as stated in the Partnership's IPO prospectus of February 3, 2006. MarkWest Energy Partners Report Earnings PRNewswire 3-09 MarkWest Energy Partners reported a net loss of $3.2 million for Q4-05, compared to net income of $3.8 million for Q4-04. For the year ended December 31, 2005, the Partnership reported net income of $2.4 million compared to net income of $10.0 million for the year ended December 31, 2004. Distributable Cash Flow (DCF) for Q4-05 was $13.1 million, compared to $14.2 million for Q4-04. For the year 2005, DCF was $44.0 million, compared to $37.0 million for 2004. XTEX Reports Earnings PRNewswire 3-10 XTEX reported net income of $10.5 million, or $0.33/unit, in Q4-05, compared to net income in Q4-04 of $6.1 million, or $0.23/unit. Net income in Q4-05 was impacted by a $2.3 million gain during the quarter from the mark-to-market valuation of the derivative financial instruments (puts) purchased to protect against liquid prices fluctuations in conjunction with the South Louisiana processing business. Full year 2005 net income was $19.2 million, or $0.56/unit, compared to net income of $23.7 million or $0.98/unit in 2004. The year's net income was reduced by the impact of the fair value loss of $9.2 million from the puts previously described. Neither the gains associated with the puts in Q4 nor the fair value loss for the year had any impact on distributable cash flow. XTEX's Distributable Cash Flow for Q4-05 was $22.2 million, or 3.48 times the amount required to cover its Minimum Quarterly Distribution of $0.25 per unit, and 1.31 times the amount required to cover its recently increased distribution of $0.51 per unit. This is an increase of $10.3 million, or 87%, over Distributable Cash Flow of $11.9 million in Q4-04. Q4-05 Distributable Cash Flow was $3.6 million in excess of the amount needed to provide 1.1 times coverage of the fourth quarter distribution of $0.51. For the full year of 2005, Distributable Cash Flow was $64.6 million, or 2.53 times the amount required to cover the Minimum Quarterly Distribution and 1.29 times the amount required to cover its actual distributions of $50.1 million. Distributable Cash Flow for 2005 increased more than 53% from the 2004 figure of $42.2 million. The increase in Distributable Cash Flow in Q4-05 was due to growth in XTEX's gross margin to $56.4 million compared to $33.9 million in Q4-04, an increase of 66%. Gross margin from the Midstream business segment increased by $18.9 million, or 72%, to $45.1 million driven in large part by South Louisiana processing margins of $14.1 million and market volatility. The quarter was negatively impacted by reduced throughput volumes on the new South Louisiana processing assets as a result of damage by Katrina and Rita to production and pipeline facilities owned by others in the Gulf of Mexico. XTEX took advantage of arbitrage opportunities resulting from market volatility in the aftermath of the hurricanes which more than offset the negative impact of the reduced volumes. Additionally, XTEX negotiated a purchase price reduction on these assets due to the negative impacts on volumes foreseen prior to their acquisition. Volumes should begin to increase in these assets over the first two quarters of 2006 as natural gas producers and pipelines complete repairs to their infrastructure and resume full production, although it may be Q3 before volumes are back to levels consistent with original acquisition expectations. The excess cash flow generated in Q4-05 and the purchase price reduction obtained on the South Louisiana processing assets will be considered in setting the distribution in Q1-06. Gross margin for the quarter from the Treating segment increased by $3.9 million, or 55%, to $10.8 million due to the increase in the number of plants in service. The number of treating plants in service increased from 74 at the end of Q4-04 to 112 at the end of Q4-05. For similar reasons, overall gross margin for the year increased from $114.5 million to $162.5 million, an increase of 42%. Of the $48.0 million gross margin increase for the year, $35 million was contributed from the midstream segment. Treating margins improved $13 million year-over-year. These improvements were offset by increases in operating expenses of $7.5 million and $18.4 million for the fourth quarter and full year, respectively, primarily associated with the new assets in service. General and administrative expenses increased by $3.3 million and $11.8 million for the fourth quarter and full year, respectively. This increase is related to the staffing increases from the South Louisiana processing acquisition, the North Texas Pipeline construction activity, the growth in treating plants and other growth. Interest expense increased $3.4 million and $6.5 million for the fourth quarter and full year, respectively, due to increased debt to support growth activities. XTEX's capital structure is still very conservative, having recently raised $228 million of equity, representing approximately 47% of the purchase price of the South Louisiana processing assets. On 3-20 XTEX announced that it anticipates it will generate net income in 2006 of between $18.0 million and $26.0 million, and its estimate of Distributable Cash Flow for the year is in the range of $84.5 million to $95.5 million. Total maintenance capital expenditures are expected to be between $10 and $14 million in 2006. XTEX currently expects to pay total distributions for this year between $2.10 and $2.20 per unit. Based on that range the Corporation would receive total distributions between $40.6 million and $44.3 million from XTEX. XTXI anticipates direct cash expenses associated with its operations outside of XTEX of approximately $1.5 million. The XTXI expects that it will incur only nominal current year income tax expense due to tax loss carryforwards and other tax benefits it expects to use in 2006. However, it will continue to set its dividends as if it were a taxpayer. Therefore, XTXI expects to pay dividends of between $2.40 and $2.65 per share in 2006. Martin Midstream Partners Reports Earnings PRNewswire 3-14 MMLP reported net income for Q4-05 of $2.6 million on revenues of $144.6 million compared to Q4-04 of $4.4 million on revenues of $91.6 million. MMLP's net income per limited partner unit for Q4-05 was $0.28 compared to $0.51 for Q4-04. MMLP reported net income for the year of $13.9 million on revenues of $438.4 million compared to 2004's $12.3 million on revenues of $294.1 million. MMLP's net income per limited partner unit for 2005 was $1.58 compared to net income per limited partner unit for 2004 of $1.45. MMLP's distributable cash flow for 2005 was $21.1 million, or 1.11 times the actual cash distributed by MMLP to unitholders in 2005. MMLP's distributable cash flow for 2004 was $18.0 million, or 1.03 times the actual cash distributed by MMLP to unitholders in 2004. As a result of the growth in distributable cash flow, MMLP increased its 2005 quarterly distributions per limited partner unit from $0.535 paid in respect of Q1-05 to $0.61 paid in respect of Q4-05. Q4-05 results were negatively impacted by $0.09 per limited partner unit due to the down-time resulting from the conversion of one of MMLP's offshore marine vessels and the conversion of tankage at its Tampa terminal to different product specifications. MMLP anticipates that the conversion of these assets should result in higher levels of service at higher margins in 2006. Ruben Martin, President and Chief Executive Officer of Martin Midstream GP LLC, MMLP's general partner, stated: "2005 has been a pivotal year for our company. Prism Gas, our largest acquisition to date, has been successfully integrated with our company and has provided us with immediate entry into the growing East Texas and North Louisiana natural gas gathering and processing business. Furthermore, the acquisition of Prism Gas has provided us with substantial organic growth opportunities at favorable rates of return in 2006 and beyond. We currently have $70 to $80 million in organic growth projects currently in progress, which we anticipate will come on line in 2006 and 2007. In addition to our growing natural gas/LPG services segment, we have also experienced significant growth in our newly formed sulfur segment. With the acquisitions of Bay Sulfur and the remaining interest in CF Martin Sulphur during 2005, as well as the construction of a new sulfur processing facility at our Neches terminal, we have further developed our sulfur gathering, processing and distribution infrastructure. This expanded infrastructure gives us and our customers access to the world sulfur markets. We look forward to a full year of operations from Prism Gas and these new sulfur assets." PAA to Acquire Natural Gas Liquids Businesses From Andrews PRNewswire 3-15 Plains All American Pipeline announced that through its subsidiary, Plains LPG Services, L.P., it has signed a definitive agreement to acquire 100% of the equity interests of Andrews Petroleum, Inc. and Lone Star Trucking, Inc. for approximately $205 million. The transaction is expected to close in the next 30 days, subject to receipt of regulatory approval and satisfaction of customary closing conditions. The primary assets consist of 200,000 barrels of NGL storage; a processing facility with butane isomerization capacity of 14,000 barrels per day and NGL fractionation capacity of 9,600 barrels per day; a rail rack with the ability to service 30 tankcars; a truck rack with the ability to service seven trucks; a fleet of over 50 tractor trailers and office facilities in California. The Partnership noted that the EBITDA generated by these companies were approximately $22.4 million in 2005. PAA also announced that it has received commitments from a group of funds affiliated with nine institutional investors led by Zimmer Lucas Capital, LLC and Kayne Anderson Capital Advisors, L.P. The commitments provide for the sale by PAA of up to approximately 3.5 million common units to fund a portion of the acquisition of Andrews Petroleum. The investors will purchase a minimum of approximately 2.3 million common units at a price of $42.80 per unit for proceeds of $100 million. The sales price represents a 4.0% discount to both the closing price on March 10, 2006 and the average closing price for the last 15 trading days ended March 14, 2006, the last full trading day prior to the execution of the agreement. Kramer noted that the 4.0% discount is roughly equivalent to the average underwriting discount typically paid in connection with an underwritten public offering. MarkWest Hydrocarbon Reports Loss PRNewswire 3-21 MarkWest Hydrocarbon [MWP] reported a net loss of $1.0 million for the three months ended December 31, 2005, or an $0.09 loss per diluted share, compared to net income of $6.7 million, or $0.63 per diluted share, for the fourth quarter of 2004. For the year ended December 31, 2005, the Company reported a net loss of $6.8 million, or $0.63 per diluted share, compared to a net loss of $0.9 million, or $0.08 per diluted share, for the year ended December 31, 2004. MarkWest Energy Partners, L.P. [MWE] reported income from operations of $13.5 million in the fourth quarter of 2005, up from $8.6 million in the fourth quarter of 2004. For the year ended December 31, 2005 MarkWest Energy Partners, L.P. reported income from operations of $33.3 million, up from $24.4 million for the year ended December 31, 2004. PAA to Sell Shares Reuters 3-21 Plains All American Pipeline LP said it reached a deal to sell 2.3 million common units at $42.80 each to several institutional investors. Prior to the announcement, PAA had 73.77 million shares outstanding [Yahoo data]. Hiland Announces $93 Million Acquisition of Gathering Assets From Enogex PRNewswire 3-30 Hiland Partners (HLND) announced that it had executed a definitive agreement with Enogex Gas Gathering, L.L.C. to acquire Enogex's Eastern Oklahoma gathering assets for $93 million. expects the transaction to be immediately accretive to its distributable cash flow per unit. The assets to be acquired include five separate low pressure natural gas gathering systems located in the Eastern Oklahoma Arkoma Basin that includes nearly 40,000 horsepower of compression and over 550 miles of natural gas gathering pipelines that is currently gathering approximately 145,000 mmcfd. Valero Energy Files IPO Registration Statement fpr Valero GP Holdings Businesswire 3-31 Valero Energy Corporation (VLO) announced that its subsidiary Valero GP Holdings, LLC has filed a registration statement on Form S-1 with the SEC for an initial public offering of approximately 37% of its units representing limited liability company interests. All units will be sold by subsidiaries of Valero Energy Corporation, which initially will retain an approximate 63% ownership interest in Valero GP Holdings, LLC, the owner of the general partner interest, the incentive distribution rights and a 21.4% limited partner interest in Valero L.P. (VLI), a publicly traded limited partnership. Valero Energy has stated its intention to further reduce and ultimately sell all of its interest in Valero GP Holdings, LLC, pending market conditions. LNG Companies Mull Conversion to MLPs Investment Dealers' Digest, 3-20 The master limited partnership structure, used most often by oil and gas pipeline companies since Goldman Sachs revived it in 2001 [for KMP], is increasingly being considered by players in the up-and-coming liquefied natural gas sector. Only one company in the LNG chain has used it so far-shipper Teekay LNG Partners used it for its IPO last May-but a number of others are said to be considering adopting it, the most prominent being Houston-based Southern Union, a natural gas pipeline company that owns and operates an LNG terminal in the US. Changes in the tax law during the Reagan era of the 1980s made MLPs off-limits for a decade-plus until Goldman found a way to make them palatable again to institutional investors. Any candidate for the MLP structure has to throw off a sustainable and steady cash-flow stream and be able to support cash distributions. LNG terminals with long-term contracts in place, not to mention expansion plans, fit that bill on both counts. MLPs' tax-friendly structure makes LNG companies want to drop assets down into the structure, in which the LNG companies would retain an interest and act as general partner. Southern Union has a long-term contract in place for at least 20 years with British Gas. It also has an expansion plan in place for its LNG facility at Lake Charles, La., that it calls Trunkline. "Southern Union is looking pretty hard at this," said an analyst familiar with the company's plans. Other potential adoptees of the MLP structure include El Paso, Sempra Energy, Suez, Dominion Resources and Cheniere Energy. "These companies would put the assets into an MLP and retain an interest and return as the managing member," said Keith Martin, a partner at Washington DC-based law firm Chadbourne & Parke. Southern Union will likely recapitalize its LNG assets before Cheniere because its LNG operations are more mature. Cheniere, whose LNG facility is set to come online in 2008, has secured long-term contracts with Chevron and Total, but those agreements do not kick in until 2009. "Cheniere is highly unlikely to MLP its terminals in 2006," said Anatol Feygin, a natural gas analyst at Banc of America Securities. But other LNG companies may follow soon after Southern Union's expected deal and beat Cheniere to the punch (Southern Union officials did not return a call for comment). "This issue isn't lost on any of those companies," Feygin said. "Every single one of them knows that it's an interesting and attractive option. All are evaluating MLPs at this point, and all are intent on pursuing them." Teekay LNG Partners is somewhat different from the newest wave of companies mulling an MLP structure. It transports LNG and crude oil, while the others operate LNG facilities. Teekay was able to move more quickly than its rivals because two years ago it acquired Spanish LNG carrier Naviera F. Tapias, a company that was actively managing an LNG fleet. Since the MLP started trading last May, its market value has jumped 27%. "We see a $15 billion market opportunity in the next 2-3 years, which would roughly translate into an additional 60-70 ships required to service new and expanding LNG projects," said a Teekay LNG official. Currently, about 20% of eligible energy assets in the US are held in MLPs, as are about 34% of US oil and gas pipeline assets, according to Chadbourne & Parke. However, there are potential roadblocks that could hinder LNG companies from successfully forming partnerships. For instance, while there is no shortage of proposed and approved LNG facilities, they are extremely capital intensive and require faith on the part of investors that natural gas prices will remain high. "I think the ability to sell MLPs is going to be hindered by a sense of uncertainty surrounding how many projects will go through," said an attorney at another East Coast law firm. Of course, energy MLPs are just as vulnerable as other energy companies to a severe pullback in prices. "If commodity prices fall, that could take some of the shine off MLPs for investors," said Martin. Texas Oil & Gas Update Dan Piller, Fort Worth Star-Telegram, 3-06 If Texas' oil and gas industries were baseball teams headed to spring training, the scouting reports would read something like this: OIL: The once-dominant Texas oil industry has fallen into a slump caused by age. The state's legendary fields, which gushed oil when first tapped, have been depleted over the decades. Statewide production in 2005 of 344.4 million barrels was down 33% from a decade earlier. Texas produced more oil in 1935 than it did last year. A few of the state's hall-of-fame fields, most notably the Spraberry Trend, Wasson, Slaughter and Yates fields in the Permian Basin of West Texas, are holding their own. But many more of Texas' famous old fields, including the giant East Texas field and the big fields near the Gulf Coast in Southeast Texas where the state's oil industry originated a century ago, produce just a fraction of their peak of past decades and have been abandoned by the major oil companies. While most of Texas' oil fields are in decline, the state hasn't discovered a major new oil field since the opening of the Giddings Field in South Central Texas and the Fairway Field in East Texas, both in 1960. The biggest Permian Basin fields, home to almost 70% of Texas' crude production, are at least a half-century old and need injections of water and carbon dioxide to maintain production. "We're just basically staying in place," said Russ Hall, a well engineering consultant based in Midland who has worked the Permian Basin all his life. Oil production in the Permian Basin has declined 24% since 1995. Hall says the state's overall problem is a lack of new fields. "We've pretty much found all the oil in Texas that there is," he says. "There's more oil down there, but it's hard to drill and expensive. There's no magic bullet here." NATURAL GAS: In contrast to oil, gas production in Texas is up from 4.5 trillion cubic feet a decade ago to about 5.1 trillion cubic feet last year. The growth can be explained in two words: Barnett Shale. Sophisticated uses of technologies, such as 3-D seismic imaging, hydraulic fracturing and horizontal drilling, have enabled the North Texas field surrounding Fort Worth to become the cleanup hitter of the Texas energy industry. Production from the Barnett Shale reached almost 450 billion cubic feet in 2005, doubling the 220 billion cubic feet it produced in 2002. In 2005 the focus of Barnett Shale drilling moved south from its original base in Wise and Denton counties to Tarrant, Johnson and Parker counties. The opening of two major pipelines has been an added stimulus to well development. As Aubrey McClendon, chairman of Chesapeake Energy, told analysts a week ago, "Johnson County is the real sweet spot for the Barnett Shale." Tarrant County, for the first time in Texas' history, became one of the state's Top 10 gas producing counties, with 94 billion cubic feet of production from wells rising midmetropolis along roadsides, in vacant lots and parks, in back yards and on the edge of neighborhoods. With more than 20% of the 650 drilling rigs in Texas now working the Barnett Shale, the field is likely to continue its production growth, at least in the short term. The Barnett play this year is moving south into Hill and Ellis counties and west into Erath, Jack, Montague and Palo Pinto counties. The independent operators that have developed the Barnett Shale so far, such as Devon Energy, Chesapeake Energy, XTO Energy, Quicksilver Resources and Chief Oil & Gas, are being supplemented by the majors, such as Exxon Mobil, Shell Energy, Marathon Oil and ConocoPhillips. They entered the Barnett Shale via purchases, joint ventures or leasing. The Barnett Shale is getting help in natural-gas production from middle-aged Texas fields that it has surpassed, such as Carthage in Panola County and Freestone County southeast of Dallas-Fort Worth; Lobo Consolidated in far South Texas, along the Rio Grande River; and the Snyder Field in the Permian Basin. East Texas, home of the state's all-time best-producing oil field dating back to the early 1930s, has virtually given up new crude oil production in favor of drilling for gas in the prolific Cotton Valley and Bossier sandstone formations. "Everybody over here is chasing natural gas now," says James Smith, a Tyler geologist and four-decade veteran of East Texas drilling. There are a couple of problem spots in Texas' natural-gas lineup. The venerable Panhandle West field near Amarillo, which leads all Texas gas fields with more than 20 trillion cubic feet of production since it opened seven decades ago, is clearly on the downside with production dropping at the rate of 12% annually. Absent a burst of new drilling the Panhandle West could be exhausted within a decade. "The future for natural gas in Texas is in unconventional fields like the Barnett Shale, where new technology can be brought into play," said Dr. Ian Duncan of the University of Texas Bureau of Economic Geology. "The Giddings Field could be anticipated to run down fast; the gas is trapped in natural faults and comes out quickly. The Barnett should deplete more slowly." Some interesting new natural gas fields have come into play in the past five years while the industry has focused on the Barnett Shale. In East Texas, the Oak Hill Field, overlaying the historic East Texas oil field near Kilgore, doubled its production since 2000. The Buffalo Wallow field in the Panhandle along the Oklahoma border did the same thing from 2004 to 2005, taking up some of the slack of the slowly exhausted Panhandle West Field nearby. In far West Texas under the Texas-New Mexico border, the Haley Field in Loving County also doubled production last year. Haley isn't for cash-poor beginners; wells are 18,000 feet deep and production costs start at $5 million (double the price of an 8,000-foot Barnett Shale well) and can easily top $10 million. "It's a tough, expensive field to drill, but they're getting production," said Midland consultant Hall. An even more intriguing play is directly west of Loving County in Culberson County, where big independents are rushing to take leases for what is whispered to be a Barnett Shale-like play. So while little prospect of young oil fields appears on the Texas horizon, the state has several promising natural-gas prospects and a roster of well-capitalized independent producers eager for development. "Everybody is looking for the next Barnett Shale," geologist Duncan said. "At least in natural-gas production, there's a chance we'll find it." A Tale of Two Fields: Giddings & Barnett Shale Dan Piller, Fort Worth Star-Telegram, 3-07 A decade ago, the Giddings Field in the Austin Chalk limestone formation was the Barnett Shale of its day: Texas' leading energy producer and the talk of the industry. From 1993 to 1997, the field led Texas in production of natural gas and crude oil, an unprecedented double. Giddings' biggest operator, Union Pacific Resources of Fort Worth, produced more natural gas in 1996 and 1997 than Exxon, Conoco, Shell or Enron. "Back then we had 27 rigs drilling, and if an oil well didn't come in at 1,000 barrels per day, we didn't think it was worth much," said Darrell Chmelar, who was a production supervisor for Union Pacific Resources. But today, the Giddings Field serves as a cautionary tale for the boomtown euphoria that has settled over the Barnett Shale around Fort Worth, where production has doubled since 2002. Natural-gas production from Giddings has fallen from a state-leading 294 billion cubic feet in 1996, to 60.6 billion cubic feet last year. Oil production from Giddings has also dropped, from a state-best peak of 32 million barrels in 1993, to 6.1 million barrels last year. That decline is a sobering reminder that in the oil patch, things can go downhill in a hurry. And it leaves unanswered a question that vexes engineers and geologists: whether horizontal drilling, fracturing and other new technologies used by today's operators effectively tap new sources of oil and gas but produce them at faster initial rates and with quicker declines than the lower-tech methods used to open Texas' older fields. Chmelar and Greg Strickland, production manager for the Giddings Field, now work for Anadarko Petroleum of Houston, which acquired UPR for $8.2 billion in 2000. Strickland said Anadarko will spend $90 million this year to rework old wells with new casings, drill more lateral extensions and use high-pressure water fracturing to clean and enlarge the tiny cracks in the Austin Chalk limestone formation as far as 15,000 feet below the surface. Any oil-patch veteran will attest that revamping an old field is a greater engineering and geological challenge than drilling new wells. "We're working hard just to maintain current production," Strickland said. Anadarko will drill 35 wells in Giddings in 2006, a modest effort compared with the 140-plus wells that big operators such as Devon Energy, XTO and Chesapeake Energy plan to sink into the Barnett Shale this year. But a Giddings well is twice as deep as an 8,000-foot Barnett Shale well, takes twice as long to drill and costs at least double the $2.5 million per average of a well in the Barnett Shale. "The rock is very unforgiving here," said tool pusher Jason Coon at an Anadarko drilling site near Brenham. Despite the abrupt plunge from its leadership position, nobody is saying the Giddings Field is an abject failure. Giddings is unique among most Texas fields in its ability to be a top producer of oil and gas. With total production of 450 million barrels since its discovery in 1960 -- Texas' last major oil-field find -- Giddings ranks in the top 20 among Texas' all-time oil fields. Giddings began producing natural gas in 1978 and stands as Texas' fourth all-time best gas producer with 2 trillion cubic feet of total production. "Giddings has been a fantastic success, and nobody should be critical of its decline," said Gary Swindell, a Dallas geologist who has worked the field. Swindell notes that Giddings went through two drilling phases: an early vertical drilling period from the late 1960s through the '70s and then a renewed push with horizontal drilling beginning in the 1980s. "Horizontal drilling gave that field a big new life in the 1990s and also paved the way for the horizontal drilling that has been so successful in the Barnett Shale," Swindell said. Production declines happen in the best of fields. The Prudhoe Bay Field in Alaska, the top U.S. oil producer since it was opened in the early 1970s, has had production drop by almost 75% since the late 1980s. For that reason, President Bush has risked political capital to try to open the Arctic National Wildlife Refuge as a way to reinforce North Slope production. The legendary Permian Basin of West Texas, producer of 70% of Texas' oil, is showing its age. In 2005, the Permian produced 25% less crude than a decade earlier. But some fields hold their production better than others. The venerable Panhandle West field near Amarillo, which opened in 1933 and is the state's most prolific natural-gas field ever, was still the fifth-best producing field in 2005 despite its septuagenarian status. In East Texas near the Louisiana border, the Carthage gas field in Panola County, which opened in 1978, has shown remarkable consistency. Although Giddings lost 80% of its gas production from 1995 to 2005, Carthage increased its gas output from 166.2 billion cubic feet in 1995, to 179.7 billion cubic feet last year. But experts are more optimistic about the Barnett Shale. Ian Duncan, associate director of the Bureau of Economic Geology at the University of Texas at Austin, said that geologically, Giddings and the Barnett Shale are different creatures. He says the Barnett's inevitable decline will not be as abrupt and steep as the Giddings'. "The sharp decline in the Giddings Field shouldn't have been a surprise," Duncan said. "The Austin Chalk limestone in the Giddings is naturally fractured, or cracked. So when you drill, the early oil and gas production comes up quickly but will decline more rapidly than in most limestones or sandstones. A shale is more of a solid rock. You have to fracture it before you can produce, but then production is more steady." Conventional wisdom about the Barnett Shale, based on a half-decade of full production, is that its wells will decline by 50% to 75% after the first year of production but then produce steadily for 30 years or more. Even so, Devon Energy of Oklahoma City, which has the earliest Barnett wells in Wise and Denton counties that were drilled starting in the late '90s, has begun an aggressive effort to refracture some old wells to recapture their initial production rates. Wise County northwest of Fort Worth, where the Barnett Shale boom was born in the late 1990s, sent out a warning signal last year when its Barnett Shale production declined, from 148.2 billion cubic feet in 2004 to 144.6 billion cubic feet. Devon, the biggest operator in Wise and Denton counties, has begun to refracture its early Barnett wells to reverse declines. "It's a simple fact that the decline rate in the Austin Chalk wells is higher than in other limestones or shales," Strickland said. "We've accepted it." 2006 NYC MLP CONFERENCE Hart Energy Publishing 3-13 The 2006 annual conference of the Coalition of Publicly Traded Partnerships was held in New York on March 8-9. Some 500 buy-side investors, analysts, brokers and bankers attended the gathering that's been held since 2002. This year's conference had presentations by 26 MLPs. Since 1994, the universe of publicly traded partnerships has zoomed from seven to 46, driving market capitalization from $2 billion to over $80 billion. Yves Siegel, managing director for equity research, midstream energy and master limited partnerships for Wachovia, reported that one major theme of the conference was how organic growth has replaced acquisitions as the predominant mode of expansion. Buying assets has simply become too pricey, at 10x cash flow or more. Another trend is the placement of more and more volatile, commodity- sensitive assets into the MLP structure (i.e., natural gas processing, exploration and production and refining). The MLP management teams are in general prudently financing growth with an equal mix of debt and equity. However, the challenge may be the market's ability to digest the significant amounts of new equity that will be required to finance this growth. Institutions are increasing their exposure to MLPs, but these are primarily hedge funds, and they may not be long-term investors. Private equity funds are also becoming more prominent investors (particularly among GP ownership), but their investment time horizon is also questionable. Although retail investors own the largest proportion of MLPs (46.3% according to Price Waterhouse), Siegel suspects that MLPs are still relatively underowned by this class of investor. Although the percentages vary from MLP to MLP, generally speaking the GP's marginal interest in distributions increase to 15% at the first designated distribution (target) level moving up to 25% and ultimately 50% (called the high splits) as preestablished distribution per unit thresholds are met. Most of the older more mature MLPs are in the high splits, including: TPP, KMP, PAA, BPL and SPH (fixed at 15%). While past performance cannot guarantee future results, historically, these MLPs have been very successful in increasing distributions, which has resulted in enhanced unit value in the market. (AG Edwards Monthly Review 3-01-06) On 3-31 Goldman Sachs downgraded PAA to Underperform from In-Line, saying that PAA's valuation premium is not justified by distribution growth forecast. On 3-29 Wachovia Upgraded TLP from Market Perform to Outperform. On 3-22 Analysts at Lehman Brothers reinitiate coverage of MMP with an "overweight" rating. On 3-22 Wachovia Initiated coverage of MGG at Outperform, Credit Suisse Initiated coverage at Outperform, and Deutsche Securities Initiated coverage at Hold. On 3-17 Lehman Brothers Downgraded HEP from Overweight to Equal-weight. On 3-16 RBC Capital Mkts Upgraded MMLP from Sector Perform to Outperform. In a research note published this morning, the analyst mentions that the company has reported its 4Q EPU in-line with the estimates and short of the consensus. Martin Midstream Partners’ recent equity offering has improved the company’s balance sheet and trading liquidity, the analyst says. RBC Capital Markets expresses its optimism regarding the company’s above-average return potential. On 3-15 Credit Suisse Initiated coverage of ETP at Outperform. On 3-16 Analyst Mark Easterbrook of RBC Capital Markets maintains his "outperform" rating on ETP. The target price has been raised from $40 to $45. In a research note published yesterday, the analyst mentions that Energy Transfer Partners' 1Q net income was significantly ahead of the consensus, exhibiting the strategic power of the company's assets. Energy Transfer Partners is poised for organic growth in the Texas market, given its ongoing projects, the analyst says. The company has raised its EBITDA guidance for 2006 from $575 million to $650 million and its distribution to $0.35 per unit on an annualized basis. On 3-13 UBS Upgraded NBP from Neutral to Buy. On 3-09 KeyBanc Capital Mkts / McDonald Upgraded Copano from Hold to Buy. On 3-02 Deutsche Securities Downgraded VLI from Buy to Hold. On 2-27 Harris Nesbitt Upgraded NBP from Underperform to Neutral and RBC Capital Mkts Downgraded PAA from Outperform to Sector Perform. On 3-24 Kayne Anderson Energy Total Return Fund (KYE) announced the Fund's net assets were $796 million and its net asset value per share was $24.72 based on 32.2 million shares outstanding. On this date, the Fund's discount to NAV was approximately 7.3%. Accordingly, the Fund will authorize its agents to make open market purchases of the Fund's shares consistent with the Fund's Stock Repurchase Program announced on January 30, 2006. On 3-20 Energy Income and Growth Fund (FEN) has declared its regularly scheduled quarterly distribution of $0.34 per share. This is a $0.005 per share (1.49%) increase from the previous quarter's distribution of $0.335 per share. Based on the Fund's net asset value of $23.11 and the closing market price of $21.28 on March 17, FEN's regular distribution equates to an annualized distribution rate of 5.88% at NAV and 6.39% at market price. On 3-22 Kayne Anderson MLP Investment Company (KYN) declared its quarterly dividend of $0.43 per share for the period December 1, 2005 to February 28, 2006. This represents an annualized dividend yield of 6.8% based on KYN's closing stock price of $25.26 per share as of March 21, 2006. The dividend of $0.43 per share represents an increase of 1.2% from the prior quarter's dividend and represents a 14.7% increase from KYN's initial dividend rate. On 3-22 Kayne Anderson Energy Total Return Fund (KYE) declared its quarterly dividend of $0.415 per share for the period December 1, 2005 to February 28, 2006. This represents an annualized dividend yield of 7.3% based on KYE's closing stock price of $22.59 per share as of March 21, 2006. The dividend of $0.415 per share represents an increase of 2.2% from the prior quarter's dividend. NOTE #1: This page is ment to be a supplement for those already getting monthly sector updates from their broker. It hopes to provide more timely data - and cover a wider array of stocks and different valuation metrics. Data entry errors sporadically happen. These supplemental stats omit metrics like Debt/Market Cap and the GP/LP split ratios - but YOU should not. NOTE #2: The operator of this site owns units in BWP, EPD, ETP and PAA - and this could distort the coverage of those MLPs. Candidates for future acquisition include APL, CPNO, HLND, MMP and SXL - so news on those will disproportionately draw my attention. Those MLPs with slower distribution growth may have coverage that is slighted. NOTE #3: For MLPs to be in my coverage universe, I must be able to find DCF and EPS estimates for them, they must have been in existence since the first of the coverage year. This is why GEL is not in the universe, and why BWP, HLND, TGP, TLP, USS and WPZ were added in 2006. NOTE #4: Those wishing to contribute DCF data to this site can do so by contacting Bob Martin at factoids@flash.net -- The only way we are going to get consensus DCF stats is if we build them ourselves, and that takes a team effort. This site frequently uses data provided by the members of the 'MLP and Royalty Trust' Yahoo group. |