Ron Hiram

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Professional Experience

CEO at Cellnet Solutions Ltd., Feb '08 - Feb '10
Managing Partner at Federmann Enterprises (Eurofund), Sep '02 - Feb '08
Partner at TeleSoft Partners, Dec '00 - Jul '02
Managing Director at Lehman Brothers, May '81 - Mar '94
Partner at Aoros Fund Management, Mar '94 - Nov '00

Education

MBA at Columbia University, Aug '79 - May '81

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Wise Analysis
A Closer Look at Magellan Midstream Partners' Distributable Cash Flow as of 4Q 2012
  • by , 1 years ago
  • tags: MMP PAA WPZ
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool Revenues, operating income, net income and earnings before interest, depreciation & amortization and income tax expenses (EBITDA) reported by Magellan Midstream Partners, L.P. (MMP) for 4Q12, 2012 and prior periods are summarized in Table 1: Period: 4Q12 4Q11 2012 2011 2010 Revenues 503 487 1,772 1,749 1,557 Operating income 183 140 552 523 408 Net income 154 110 436 414 312 EBITDA 215 170 678 642 515 Adjusted EBITDA 224 191 716 636 538 Weighted average units o/s (million) 227 227 227 226 219 Table 1: Figures in $ Millions All the operating parameters in Table 1 exhibited modest increases in 2012 vs. 2011. In the last 3 years MMP has not increased significantly the number of limited partner units outstanding, a significant accomplishment when compared to most of the master limited partnerships (“MLPs”) that I follow. Effective January 1, 2013, MMP has redesigned its internal management reports to correspond to a new organizational structure that reflects redefined reporting segments. The new reporting segments are: 1) refined products pipeline and terminals; 2) crude pipeline and terminals; and 3) marine storage. The refined products pipeline and terminals segment incorporates most of MMP’s petroleum pipeline system, the inland terminals and the ammonia pipeline system. The crude pipeline and terminals segment: incorporates: a) the Crane-to-Houston crude pipeline reversal project; b) the Cushing pipeline and terminal; c) the South Texas crude pipeline; d) the crude components of the East Houston (Corpus Christi) terminal; e) the condensate components of the Corpus Christi, Texas terminal; f) the Gibson, Louisiana terminal; and g) equity earnings of the Osage pipeline, the Double Eagle pipeline, and the BridgeTex pipeline. The marine storage segment incorporates the six petroleum terminals that have marine access and are located near major refining hubs along the U.S. Gulf and East Coasts. Segment operating margins are shown in Table 2 below: Period: 4Q12 4Q11 2012 2011 2010 Operating margin: Refined Products 194 150 593 574 491 Operating margin: Crude Oil 22 21 91 74 29 Operating margin: Marine Storage 31 27 102 92 90 Allocated corporate depreciation 1 1 3 3 3 Total operating margin 249 199 789 743 612 Depreciation and amortization (33) (31) (128) (121) (109) General and administrative expense (33) (28) (109) (99) (95) Total operating profit 183 140 552 523 408 Table 2: Figures in $ Millions The bulk of the operating margins seen in Table 2 are generated by fee-based transportation and terminals services, with commodity-related activities contributing 15% or less of MMP’s operating margin. MMP’s definition of Distributable Cash Flow (“DCF”) and a comparison to definitions used by other master limited partnerships (“MLPs”) are described in one of my prior articles . Using that definition, DCF in 2012 was $540 million ($2.38 per unit), up from $461 million ($2.03 per unit) in 2011. As always, I first attempt to assess how these figures compare with what I call sustainable DCF for these periods and whether distributions were funded by additional debt or issuing additional units. The generic reasons why DCF as reported by the MLP may differ from sustainable DCF are reviewed in an article titled Estimating Sustainable DCF-Why and How . Applying the method described there to MMP generates the comparison outlined in Table 3 below: Period: 4Q12 4Q11 2012 2011 Net cash provided by operating activities 233 151 645 577 Less: Maintenance capital expenditures (17) (32) (64) (70) Less: Working capital (generated) (31) (3) (43) (14) Sustainable DCF 185 117 538 493 Risk management activities (6) 15 13 (22) Other 0 (1) (11) (10) DCF as reported 179 131 540 461 Table 3: Figures in $ Millions Management’s initial 2012 DCF target was $490 million. This target was subsequently raised to $525 million and the $540 million actually achieved surpassed even that. Management currently projects MMP will generate $570 million of DCF in 2013 and is targeting 10% distribution growth for both 2013 and 2014. The principal differences of between sustainable and reported DCF numbers are attributable to risk management activities. I do not generally consider cash generated by risk management activities to be sustainable, although I recognize that one could reasonable argue that bona fide hedging of commodity price risks should be included. MMP’s risk management activities seem to be directly related to such hedging, so I could go both ways on this. In any event, the differences between reported and sustainable DCF in the periods under are not material. Coverage ratios appear strong, as indicated in Table 4 below: Period: 4Q12 4Q11 2012 2011 Distributions actually made 110 90 403 351 Reported DCF 179 131 540 461 Sustainable DCF 185 117 538 493 Coverage ratio based on reported DCF 1.63 1.46 1.34 1.31 Coverage ratio based on sustainable DCF 1.69 1.29 1.33 1.40 Table 4 The simplified cash flow statement in the table below gives a clear picture of how distributions have been funded in the last two years. The table nets certain items (e.g., debt incurred vs. repaid) and separates cash generation from cash consumption. Simplified Sources and Uses of Funds Period: 4Q12 4Q11 2012 2011 Capital expenditures ex maintenance & net of proceeds from sale of PP&E (96) (18) (234) (121) Acquisitions, investments (net of sale proceeds) (37) (2) (75) (66) Other CF from financing activities, net - - (2) (1) (134) (20) (311) (189) Net cash from operations, less maintenance capex, net income from non-controlling interests, & distributions 106 29 177 156 Cash contributions/distributions related to affiliates & non-controlling interests 4 - 5 - Debt incurred (repaid) 241 3 247 236 Other CF from investing activities, net - (1) - (1) Other CF from financing activities, net 11 - - - 361 31 429 391 Net change in cash 228 12 119 202 Table 5: Figures in $ Millions The numbers indicate solid, sustainable, performance. Net cash from operations, less maintenance capital expenditures, less cash related to net income attributable to non-partners exceeded distributions by $177 million in 2012 and by $156 million in 2011. MMP is not using cash raised from issuance of debt and equity to fund distributions. The excess enables MMP to reduce reliance on the issuance of additional partnership units or debt to fund expansion projects. The cash balance at year-end ($328 million) represents an extraordinarily high level relative to past periods. Given the importance of certain expansion projects discussed below, management believes it prudent “ to keep a bit more cushion to allow these large-scale projects more than adequate time to come online safely and reliably ”. In over two years (since 3Q 2010), MMP has not issued additional partnership units (excluding units issued in connection with compensation arrangements), a rare achievement in the MLP universe. Also, MMP’s net income per unit in 3012 exceeded that year’s distributions ($1.92 vs. $1.8763). That too is a rare achievement for an MLP, all the more because of its consistency (net income equaled or exceeded distributions in all but 3 of the past 12 quarters). MMP spent $199 million and $365 million on acquisitions and growth projects during 2011 and 2012, respectively. It currently expect to spend ~$700 million in 2013 on projects now underway, with additional spending of approximately $290 million in 2014 to complete these projects. These expansion capital estimates exclude potential acquisitions or spending on more than $500 million of other potential growth projects in earlier stages of development. Of the projects currently under way, the conversion of a large portion of the partnership’s Houston-to-El Paso pipeline to crude oil service is of particular note. At $375 million, this is the largest organic growth project ever undertaken by MMP. The reversed pipeline system will transport crude oil from Crane, Texas, to refiners or third-party pipelines in Houston and Texas City, Texas. Pipeline capacity will be 225,000 barrels per day and the entire capacity is 90% subscribed with Permian Basin production (10% of capacity is set aside for spot shippers). Subject to receiving the necessary permits and regulatory approvals, MMP will begin moving at least 75,000 barrels a day of crude oil to Houston in early 2013 and increase to the full 225,000 barrels a day capacity in the second half of 2013. The reversed pipeline is expected to have a materially favorable impact on MMP’s results of operations beginning in 2013. Another major project is the BridgeTex Pipeline Company, LLC (“BridgeTex”), a joint venture formed in November 2012 by MMP and affiliates of Occidental Petroleum Corporation for the purpose of constructing and operating a 400-mile pipeline capable of transporting 300,000 barrels per day of Permian Basin crude oil from Colorado City, Texas for delivery to MMP’s East Houston, Texas terminal; a 50-mile pipeline between East Houston and Texas City, Texas; and approximately 2.6 million barrels of storage. Completion is expected in mid-2014 and MMP expects to spend ~$600 million for its 50% stake in BridgeTex. MMP’s current yield is at the lowest end of the MLP universe. A comparison to some of the MLPs I follow is provided in Table 6 below: As of 4/2/13: Price Quarterly Distribution Yield Magellan Midstream Partners (MMP) $52.33 $0.50000 3.82% Plains All American Pipeline (PAA) $56.58 $0.56250 3.98% Enterprise Products Partners (EPD) $61.25 $0.66000 4.31% El Paso Pipeline Partners (EPB) $44.01 $0.61000 5.54% Inergy (NRGY) $20.88 $0.29000 5.56% Kinder Morgan Energy Partners (KMP) $90.00 $1.29000 5.73% Targa Resources Partners (NGLS) $46.09 $0.68000 5.90% Williams Partners (WPZ) $51.88 $0.82750 6.38% Buckeye Partners (BPL) $60.46 $1.03750 6.86% Energy Transfer Partners (ETP) $50.59 $0.89375 7.07% Regency Energy Partners (RGP) $25.40 $0.46000 7.24% Boardwalk Pipeline Partners (BWP) $29.35 $0.53250 7.26% Suburban Propane Partners (SPH) $45.12 $0.87500 7.76% Table 6 MMP’s premium price may be justified given its performance track record, a management team that is disciplined and unwilling to pay the premiums that other MLPs have been paying for acquisitions, an impressive portfolio of growth projects, advantageous structure (no general partner incentive distributions), ability to generate significant excess cash from operations, and proven ability to minimize limited partner dilution.
    Wise Analysis
    A Closer Look at Boardwalk Pipeline Partners’ Distributable Cash Flow as of 4Q 2012
  • by , 1 years ago
  • tags: WPZ KMP KMI EPD
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool On February 20, 2013, On October 30, 2012, Boardwalk Pipeline Partners, LP (BWP) provided its 2012 annual report on Form 10-K. Revenues, operating income, net income and earnings before interest, depreciation & amortization and income tax expenses (“EBITDA”) for 4Q12, 2012 and prior periods are summarized in Table 1: Period: 4Q12 4Q11 2012 2011 2010 Operating revenues 326 301 1,185 1,143 1,117 Net revenues 298 277 1,106 1,040 1,007 Operating expenses 196 189 711 754 677 Operating income 130 112 474 389 440 Net income 90 72 306 217 289 EBITDA 198 170 727 617 658 Weighted avg. units o/s (million) 207 176 192 173 170 Table 1: Figures in $ Millions, except weighted average units outstanding Historical amounts for the year ended December 31, 2011, have been recast to retroactively reflect the acquisition of Boardwalk HP Storage Company, LLC (“HP Storage”). As a reminder, HP Storage was formed in 4Q11as a joint venture in which the BWP had a 20% stake and Boardwalk Pipelines Holding Corp. (“BPHC”, BWP’s general partner) had an 80% stake. In December 2011the joint venture paid $545.5 million to acquire seven salt dome natural gas storage caverns in Forrest County, Mississippi, with ~36.3 billion cubic feet (“Bcf”) of total storage capacity (of which ~ 23 Bcf is working gas capacity). HP Storage also operates approximately 105 miles of pipelines that connect its facilities with several major natural gas pipelines and also owns undeveloped land suitable for up to six additional storage caverns, one of which is expected to be placed in service in 2013.In February 2012, BWP acquired from its general partner, the remaining 80% equity interest in Boardwalk HP Storage Company, LLC (“HP Storage”) for ~$285 million. The revised 2011 numbers in Table 1 are presented as if the HP Storage acquisition had occurred on 12/1/2011 (the acquisition date). But they are not significantly different from what was originally reported. Operating revenues were revised up by $4.1 million, operating income as revised down by $3.5 million and net income was revised up by $3 million. In October 2012, BWP acquired PL Midstream, LLC (renamed “Louisiana Midstream”) from PL Logistics, LLC for ~$620 million in cash. Louisiana Midstream provides transportation and storage services for natural gas and natural gas liquids (“NGLs”), fractionation services for NGLs, and brine supply services for producers and consumers of petrochemicals through two hubs in southern Louisiana – the Choctaw Hub in the Mississippi River Corridor area and the Sulphur Hub in the Lake Charles area. Assets acquired include ~53.2 million barrels of salt dome storage capacity, significant brine supply infrastructure; and more than 240 miles of pipelines (including an extensive ethylene distribution system). This acquisition represents a major step for BWP in implementing its strategy to diversify from its core business (natural gas pipelines and storage) into the midstream energy businesses. Net revenues (i.e., after deducting fuel and transportation expenses) increased by $66 million in 2012 vs. 2011. But the increase was almost entirely driven by $61million of net revenues contributed by HP Storage and Boardwalk Louisiana Midstream in 4Q12. The balance is due to an increase in parking & lending (“PAL”) and storage revenues (reflecting improved market conditions), offset by a decrease in retained fuel, primarily due to lower natural gas prices. Lower natural gas prices translate into lower revenues for fuel retained in kind as payment for transportation services. Net revenues increased by $21 million in 4Q12 vs. 4Q11. Likewise, the increase was entirely driven by $25 million of net revenues contributed by HP Storage and Boardwalk Louisiana Midstream in 4Q12. Net income and EBITDA in 2012 were adversely affected by $15 million of operating expenses associated with the acquisition of HP Storage and Boardwalk Louisiana Midstream. Nevertheless, net income and EBITDA increased by ~$89 million and $110 million, respectively, in 2012 vs. 2011, primarily due to the acquisitions of Louisiana Midstream and HP Storage. Other major factors driving the 2012 increase in net income were ~$41 million of impairments and other special charges incurred in 2011. On a pro forma basis, assuming the acquisitions had occurred on January 1, 2011, 2012 revenues would have been $1,241 million, down 1% vs. $1,254 in 2011, while net income would have been $327 million in 2012 vs. $254 million in 2011 (but, as noted above, much of that improvement in net income elates to special charges incurred in 2011 and not repeated in 2012). Management warns that the amount of contracted transportation capacity which will expire in 2013 is greater than in recent years. In light of the market conditions discussed above, BWP expects that transportation contracts renewed or entered into in 2013 will be at lower rates than expiring contracts. Remaining available capacity will be marketed and sold on a short-term firm or interruptible basis, which will also be at lower rates, due to a decrease in basis spreads between locations on the pipelines. See “ Glossary of MLP Operational Terms ” for a brief description of what are firm and interruptible transportation services, and of PAL. Management noted it expects that these circumstances will negatively affect transportation revenues, EBITDA and distributable cash flows in 2013. Annual revenues associated with contracts expiring in 2013 total ~$125 million and management estimates that the combination of lower rates on contract renewals and the remarketing of turn-back capacity will result in an annual revenue reduction of approximately $40 million. BWP’s definition of Distributable Cash Flow (“DCF”) and a comparison to definitions used by other master limited partnerships (“MLPs”) are described in a prior article . Using that definition, DCF for 2012 was $500 million ($2.60 per unit), up from $419 million in 2011 ($2.42 per unit). As always, I first attempt to assess how these DCF figures compare with what I call sustainable DCF for these periods and whether distributions were funded by additional debt or issuing additional units. Given quarterly fluctuations in revenues, working capital needs and other items, it makes sense to review TTM numbers rather than quarterly numbers for the purpose of analyzing changes in reported and sustainable distributable cash flows. The generic reasons why DCF as reported by the MLP may differ from sustainable DCF are reviewed in an article titled Estimating Sustainable DCF-Why and How . Applying the method described there to BWP results generates the comparison outlined in Table 2 below: Period: 4Q12 4Q11 2012 2011 Net cash provided by operating activities 161 108 576 454 Less: Maintenance capital expenditures (29) (34) (80) (95) Less: Working capital (generated) (2) - (4) - Sustainable DCF 131 74 492 359 Working capital used - 26 - 45 Proceeds from sale of assets / disposal of liabilities 0 2 (2) 1 Other 12 38 10 13 DCF as reported 143 140 500 419 Table 2: Figures in $ Millions Under BWP’s definition, reported DCF always excludes working capital changes, whether positive or negative. In contrast, as detailed in my prior articles, I generally do not include working capital generated in the definition of sustainable DCF but I do deduct working capital invested. Despite appearing to be inconsistent, this makes sense because in order to meet my definition of sustainability the master limited partnerships should, on the one hand, generate enough capital to cover normal working capital needs. On the other hand, cash generated from working capital is not a sustainable source and I therefore ignore it. Over reasonably lengthy measurement periods, working capital generated tends to be offset by needs to invest in working capital. I therefore do not add working capital consumed to net cash provided by operating activities in deriving sustainable DCF. Cash consumed by working capital accounts for $45 million of the $60 million variance between reported and sustainable DCF in 2011. In 2012 and 2011, the principal components of items in Table 2 grouped under “Other” are non-cash interest expense and proceeds from an insurance settlement received associated with the fire at BWP’s Carthage compressor station and a legal settlement. I exclude them from the sustainable category. Coverage ratios are indicated in Table 3 below: Period: 4Q12 4Q11 2012 2011 Distributions actually made 128 108 479 420 Reported DCF 143 140 500 419 Sustainable DCF 131 74 492 359 Coverage ratio based on reported DCF 1.12 1.30 1.04 1.00 Coverage ratio based on sustainable DCF 1.02 0.69 1.03 0.86 Table 3 Distributions are not really growing ($0.5150 per unit in 4Q10 vs. $0.5325 in 4Q12, a 3.4% increase in 2 years). Despite that, coverage ratios are thin. Making them more robust will be challenging given that over 32 million units have been issued in 3 separate equity offerings so far in 2012 and that the number of units outstanding now exceeds 218 million, up ~18% from ~185 million at the beginning of the year. The simplified cash flow statement in Table 4 below nets certain items (e.g., debt incurred vs. repaid), separates cash generation from cash consumption, and gives a clear picture of how distributions have been funded in the last two years. Simplified Sources and Uses of Funds Period: 4Q12 4Q11 2012 2011 Net cash from operations, less maintenance capex, net income from non-controlling interests, & distributions - (33) - (61) Capital expenditures ex maintenance & net of proceeds from sale of PP&E (63) 23 (141) (16) Acquisitions, investments (net of sale proceeds) (989) (546) (1,274) (546) Other CF from financing activities, net (1) (1) (5) (1)   (1,053) (557) (1,420) (623)       Net cash from operations, less maintenance capex, net income from non-controlling interests, & distributions 5 - 17 - Cash contributions/distributions related to affiliates & noncontrolling interests 273 285 287 288 Debt incurred (repaid) 478 200 241 122 Partnership units  issued (retired) 291 - 848 170 Other CF from investing activities, net - 10 10 10   1,047 494 1,403 590 Net change in cash (7) (62) (18) (33) Table 4: Figures in $ Millions Net cash from operations less maintenance capital expenditures did not cover distributions in 2011 and did so (just barely) in 2012. But Table 4 does indicate that in 2012, unlike 2011, distributions were not partially financed by issuing debt and/or equity. Approximately $282 million of the $848 million of equity issuance in 2012 is an adjustment to partners’ capital. This is because the February 2012 drop down acquisition by BWP of the remaining 80% stake in HP Storage (previously held by BPHC) was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of HP Storage were recognized at their carrying amounts at the date of transfer and $281.8 million (the carrying amount of the net assets acquired) was treated as an adjustment to partners’ capital. In February 2012, BWP issued 9.2 million units at $27.55 per unit, receiving net cash proceeds of ~$250.2 million.  In an article dated 6/4/12, I said I would not be surprised to see additional partnership units being issued later this year. Indeed, in August BWP issued 11.6 million units at $27.80 per unit generating net proceeds of ~$318 million; and in October 2012 it issued 11.2 million units at $26.99 per unit generating net proceeds of ~$298 million. The most recent equity issuance was in connection with the Louisiana Midstream acquisition. In 2012 BWP had projected spending $200 million on growth capital expenditures. The actual number was ~$150 million because $50 million was pushed into the first part of 2013. Consequently, the 2013 budget for growth capital expenditures was increased by that amount and is now estimated at ~$250 million. BWP’s major expansion projects are summarized below: Southeast Market Expansion: this ~$300 million project involves constructing an interconnection between BWP’s Gulf South and HP Storage subsidiaries, adding additional compression facilities and constructing approximately 70 miles of 24” and 30” pipeline in southeastern Mississippi. The project is supported by 10-year firm agreements of primarily electric generation and industrial customers. BWP anticipates beginning construction in early 2014 and expected the project to be placed in service by 4Q14. South Texas Eagle Ford Expansion: this ~ $180 project involves constructing a 55-mile gathering pipeline and a cryogenic processing plant in south Texas. The system will be capable of gathering in excess of 0.3 Bcf per day of liquids-rich gas in the Eagle Ford Shale production area, and of processing up to 150 million cubic feet (MMcf) per day of liquids-rich gas. The project is supported by long-term fee-based gathering and processing agreements with two customers who have committed to ~50% of the plant’s processing capacity. The plant and new pipeline are expected to be placed in service in April 2013. Natural Gas Salt-Dome Storage Project: BWP is expanding HP Storage’s salt cavern working gas capacity by ~5.3 Bcf. Injections are scheduled to begin in 2Q13 and the incremental capacity has been fully contracted for the first year that this cavern will be in service. Choctaw Brine Supply Expansion Projects: these projects will expand Louisiana Midstream’s brine supply capabilities. The first project, developing a one million barrel brine pond, was placed into service January 2013. The second project consists of constructing 26 miles of 12-inch pipeline from BWP’s facilities to a petrochemical customer’s plant. This project is supported by a 20-year contract with minimum volume requirements and expansion options and is expected to be completed in 2013. In addition the projects listed above, BWP and Williams Companies, Inc. (WMB) executed a letter of intent on 3/6/13 to form a joint venture that would develop a pipeline project (the “Bluegrass Pipeline”) to transport natural gas liquids from the Marcellus and Utica shale plays to the petrochemical and export complex on the U.S. Gulf Coast, as well as the developing petrochemical market in the Northeast U.S. This project will require FERC approval and, assuming that and other hurdles will be overcome, is expected to be placed in service in 2015. BWP is required to maintain a ratio of consolidated debt to EBITDA of no more than 5:1. BWP’s total long-term debt stood at $3.5 billion as of 12/31/12, a multiple of 4.87x EBITDA for the trailing 12-months on that date. This is an improvement over the ratio in 2011 which was in excess of 5x EBITDA. BWP’s current yield compares favorably with many the other MLPs I follow, as seen in Table 5 below: As of 3/25/13: Price Quarterly Distribution Yield Magellan Midstream Partners (MMP) $52.34 $0.50000 3.82% Plains All American Pipeline (PAA) $56.00 $0.56250 4.02% Enterprise Products Partners (EPD) $59.32 $0.66000 4.45% El Paso Pipeline Partners (EPB) $43.04 $0.61000 5.67% Inergy (NRGY) $20.28 $0.29000 5.72% Kinder Morgan Energy Partners (KMP) $88.90 $1.29000 5.80% Targa Resources Partners (NGLS) $45.46 $0.68000 5.98% Williams Partners (WPZ) $50.60 $0.82750 6.54% Buckeye Partners (BPL) $59.83 $1.03750 6.94% Energy Transfer Partners (ETP) $49.50 $0.89375 7.22% Regency Energy Partners (RGP) $25.07 $0.46000 7.34% Boardwalk Pipeline Partners (BWP) $28.64 $0.53250 7.44% Suburban Propane Partners (SPH) $44.08 $0.87500 7.94% Table 5 There has been minimal distribution growth over the past two years. Given uncertainty regarding customer contract renewals and its assessment of current market conditions, management decided it would not be prudent to increase distributions. I believe this is a sound decision.  But I remain concerned about the thin coverage ratio and relatively high leverage. Despite the enticing yield, I still conclude that investors willing to add to their positions should consider other MLPs.
    Wise Analysis
    Further Thoughts On Issues Raised By Energy Transfer Partners Holdco Transaction
  • by , 1 years ago
  • tags: ETE ETP KMP KMI WPZ
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool The structure and series of transactions undertaken are complicated and I did not catch an error with respect to an acquisition’s purchase price prior to publishing my prior article on this topic. In addition to bringing up the issue that management has not explained the price being paid by ETP for 60% of Holdco, my intent was to elicit help from readers who can shed light on the appropriateness of the price. Based on reader comments, the prior article may have come across as too judgmental. For that and for the errors made I apologize. My revised analysis regarding ETP Holdco Corp. (“Holdco”), the entity formed by ETP and its general partner, Energy Transfer Equity, L.P. ( ETE ), in 2012 to own the equity interests in Southern Union Company (“SUG”) and Sunoco, Inc. is set forth below. I would welcome corrections provided by readers. Energy Transfer Partners L.P. ( ETP ) paid $5.3 billion for Sunoco Inc. Sunoco’s interests in Sunoco Logistics Partners L.P. (“SXL”) plus $2 billion in cash were carved out and retained by ETP and were thus not transferred to Holdco. However, in place of the carved-out assets ETP contributed 90,706,000 of its Class F units to Holdco. The Class F Units are entitled to 35% of the quarterly cash distribution generated by ETP and its subsidiaries other than Holdco, subject to a maximum cash distribution of $3.75 per Class F unit. Once ETP assumes full ownership of Holdco it will own its own Class F units and can effectively cancel them. At the end of the day, ETP will have paid $5.3 billion for Sunoco and, after it assumes full ownership of Holdco, will end up with 100% of the Sunoco assets (or the benefits from them). I therefore see no related-party transfer price issue with respect to Sunoco. ETE paid $5.4 billion for SUG. It sold a portion of the SUG assets (the Citrus dropdown) to ETP for $2 billion and will be paid a further $3.75 billion by ETP for the remainder of the assets once ETP assumes full ownership of Holdco. ETP, for its part, will have paid $5.75 billion for SUG, a small total consideration delta when compared to the. $5.4 billion paid by ETE. As far as I can tell, Holdco retains the benefit of all SUG asset dispositions (e.g., the economic value of the Philadelphia refinery business) that was contributed out of SUG into a joint venture with the Carlyle Group, the sale of SUG assets to Laclede Group for $1.035 billion, the SUG assets sold to Regency Energy Partners L.P. ( RGP ). Therefore the benefit of these transactions will accrue to ETP and do not impact the total consideration delta. At ETP’s current distribution rate of $0.89375 per quarter, I calculate ETE’s IDR to be $0.52 per unit. The number of ETP units to be issued is ~48 million ($2.35 billion at an assumed price of ~$49 per unit). The value of the IDRs forgone by ETE is roughly $25 million per quarter. ETE is waiving 12 full quarters (8 at 100% and 8 at 50%). Even if we ignore time value of money, this amounts to only ~$300 million, a figure that can explain the total consideration delta. I hope, but am not certain, that I understand the price being paid by ETP. It would be helpful to see an explanation forthcoming from management. My conclusion remains – preference for ETE over ETP.
    Wise Analysis
    Issues Raised By Energy Transfer Partners' Acquisition Of 60% Of ETP Holdco
  • by , 1 years ago
  • tags: ETE ETP KMI KMP
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool Energy Transfer Partners, L.P. (ETP) and Energy Transfer Equity, L.P. (ETE) announced yesterday (3/21/13) that ETP will acquire from ETE its interest in ETP Holdco Corp. (“Holdco”) for $3.75 billion of cash and ETP common units. ETP Holdco is the entity formed by ETP and ETE in 2012 to own the equity interests in Southern Union Company and Sunoco, Inc. ETE is the general partner of ETP. With this acquisition, ETP will own 100% of ETP Holdco. The deal is expected to close in the second quarter of 2013, subject to customary closing conditions. Some background information is necessary before discussing issues raised by this transaction. The $2 billion acquisition of Southern Union Company by ETE was completed on March 26, 2012. The main asset purchased via this acquisition was a 50% joint venture interest in Citrus Corp., an entity that owns 100% of the Florida Gas Transmission (“FGT”) pipeline system (a 5,400 mile pipeline system that extends from south Texas through the Gulf Coast to south Florida). The other 50% of FGT is owned by Kinder Morgan, Inc. (KMI). The $5.3 billion acquisition of Sunoco, Inc. (“Sunoco”) by ETP was completed on October 5, 2012. The main assets purchased via this acquisition were: 1) retail marketing operations that sell gasoline and middle distillates at retail service stations and operate convenience stores in 25 states; and 2) ETP’s interests in Sunoco Logistics Partners L.P. (“SXL”), a master limited partnership that owns and operates refined product pipelines, crude oil pipelines, refined product and crude oil terminals, and other assets.  ETP’s interests in SXL consist of a 2% general partner interest, 100% of the incentive distribution rights (“IDR”) and 33.53 million SXL units representing ~32% of the limited partner interests as of December 31, 2012. Holdco is an entity that was formed, and is owned, by ETP and ETE. After ETE acquired Southern Union, it contributed this asset to Holdco and received, in return, a 60% interest in Holdco. ETP therefore ended up with a 40% economic stake in Southern Union. After ETP acquired Sunoco, it contributed this asset to Holdco and received, in return, a 40% interest in Holdco. ETP ended up with a 40% economic stake in Sunoco while ETE has 60%. In sum, ETE transferred to ETP 40% of the economic interests it acquired via the $2 billion Southern Union acquisition in exchange for ETP transferring to ETE 60% of the economic interests it acquired via the $5.3 billion Sunoco acquisition. In a prior article I noted that time will tell how fair this exchange was. Given the transaction announced yesterday, a preliminary evaluation can now be done. ETP announced it was acquiring the 60% stake it does not own in Holdco for $3.75 billion (consisting of $2.35 billion of newly issued ETP common units and $1.40 billion in cash). To make the transaction more palatable for ETP, ETE has agreed to forego 100% of its IDR payments on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurs, and 50% of the IDR payments on the newly issued ETP units for the following eight consecutive quarters. Holdco currently owns and, following the transaction announced yesterday, ETP will own 100% of the assets acquired via the Southern Union Company merger and 100% of the assets acquired via the Sunoco merger. But ETP has already paid $5.3 billion (for Sunoco) and is now paying a further $3.75 billion to acquire the remainder of Holdco. All-in-all, ETP will have paid $9.05 billion for assets that were acquired for total consideration of $7.3 billion. At ETP’s current distribution rate of $0.89375 per quarter, I calculate ETE’s IDR to be $0.52 per unit. The number of ETP units to be issued is ~48 million ($2.35 billion at an assumed price of ~$49 per unit). The value of the IDRs forgone by ETE is roughly $25 million per quarter. ETE is waiving 12 full quarters (8 at 100% and 8 at 50%). Even if we ignore time value of money, this amounts to only ~$300 million, a figure far too small to explain the total consideration delta. Beyond that, analysts have estimated Holdco’s enterprise value at ~$6.2 billion using a 9.5 multiple of estimated EBITDA for 2013. Using that number would further increase the delta. I cannot understand the price being paid by ETP and I hope to see an explanation forthcoming from management. My preference for ETE over ETP has become stronger.
    Wise Analysis
    A Closer Look at Energy Transfer Partners' Distributable Cash Flow as of 4Q 2012
  • by , 1 years ago
  • tags: ETP BPL BWP SPH
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool On March 1, 2013, Energy Transfer Partners, L.P. (ETP) provided its 2012 annual report on Form 10-K. ETP’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of the Southern Union Company into ETP beginning March 26, 2012 (the date ETE acquired the Southern Union Company) and the consolidation of Sunoco, Inc. (“Sunoco”) beginning October 5, 2012 (the date ETP acquired it). These consolidations were enabled by the formation of a company called ETP Holdco (“Holdco”), an entity that is owned by ETP and its general partner, Energy Transfer Equity L.P. (“ETE”). After ETE acquired Southern Union it contributed this asset to Holdco and received, in return, a 60% interest in Holdco. ETP therefore ended up with a 40% economic stake in Southern Union while ETE has 60%. After ETP acquired Sunoco (on October 5, 2012) it contributed this asset to Holdco and received, in return, a 40% interest in Holdco. ETP ended up with a 40% economic stake in Sunoco while ETE has 60%. ETP therefore has a 40% economic stake in both Southern Union and Sunoco, while ETE has 60%. However, ETE transferred the ability to control Holdco to ETP. The logic of why ETP can claim that it really controls Holdco escapes me (since ETE controls ETP), but nevertheless, it is ETP (rather than ETE) that consolidates both Southern Union and Sunoco. This serves ETE’s desire to become more of a “pure” general partner play. The main asset purchased via the $2 billion Southern Union acquisition was a 50% joint venture interest in Citrus Corp., an entity that owns 100% of the Florida Gas Transmission (“FGT”) pipeline system (a 5,400 mile pipeline system that extends from south Texas through the Gulf Coast to south Florida). The other 50% of FGT is owned by Kinder Morgan, Inc. (KMI). The main assets purchased via the $5.3 billion Sunoco acquisition were the retail marketing operations (that sell gasoline and middle distillates at retail service stations and operate convenience stores in 25 states) and the refined product and crude oil transportation operations of Sunoco Logistics Partners L.P. (“SXL”). ETP’s interests in Sunoco Logistics consist of a 2% general partner interest, 100% of the incentive distribution rights (“IDR”) and 33.53 million SXL units representing ~32% of the limited partner interests as of December 31, 2012. Because ETP became the owner of the general partner of SXL when it acquired Sunoco, in 4Q12 it began consolidating SXL in its financial statements as well as consolidating the results of Sunoco’s retail marketing operations. If I correctly understand the complex set of Holdco transactions outlined above, I would describe it as an “apples for oranges” exchange: ETE transferred to ETP 40% of the economic interests it acquired via the $2 billion Southern Union acquisition in exchange for ETP transferring to ETE 60% of the economic interests it acquired via the $5.3 billion Sunoco acquisition. Time will tell how fair this exchange was. In principle, from a conflicts perspective it is no different to drop-down transactions typical of master limited partnerships (“MLPs”) that have general partners with significant operational assets. But these are not the only factors that make the ETP financials difficult to analyze. ETP considers Segment Adjusted EBITDA to be an important performance measure of the core profitability of its operations. It forms the basis of ETP’s internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments. In 4Q12 management changed its definition of Segment Adjusted EBITDA to reflect amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations. In prior periods, NGL Transportation and Services was the only segment that included a less than wholly owned subsidiary – the Lone Star joint venture with Regency Energy Partners, L.P. (RGP). But in future periods Segment Adjusted EBITDA will also include 100% of FGT and 100% of the Fayetteville Express Pipeline (“FEP”) even though ETP owns 50% of these ventures and previously accounted for them using the equity method). Key operating parameters are summarized in Table 1 below: Period: 4Q12 4Q11 2012 2011 2010 Total revenues 11,761 1,805 15,702 6,799 5,885 Operating income 556 332 1,279 1,242 1,006 Interest expense (282) (126) (665) (474) (413) Equity in earnings (losses) of unconsolidated affiliates 83 0 138 (51) 16 Other income 1 9 11 2 28 Gain (Loss) on sale of assets - - 1,057 - (5) Net income before taxes 359 214 1,820 719 633 Weighted average units o/s (millions) 303 222 251 208 189 Pre-tax income per unit 1.18 0.96 7.26 3.45 3.35 Table 1: Figures in $ Millions except units outstanding and per unit data Pre-tax income per unit in 2012 benefited from a $1,057 million gain on the sale of the retail propane business to AmeriGas Partners, L.P. (APU). Excluding that, the 2012 pre-tax income per unit would have been $3.04. Segment Adjusted EBITDA is summarized in Table 2 below: Period: 4Q12 4Q11 2012 2011 2010 Intrastate transportation and storage 131 153 601 667 716 Interstate transportation and storage 306 107 1,013 373 220 Midstream 103 115 438 389 329 NGL transportation and services 54 48 209 127 - Investment in Sunoco Logistics 219 - 219 - - Retail Marketing 109 - 109 - All other 29 72 155 225 276 Eliminations (3) (2) Total Segment Adjusted EBITDA 948 493 2,744 1,781 1,541   Table 2: Figures in $ Millions except units outstanding The $66 million decline in Intratstate’s Segment Adjusted EBITDA in 2012 resulted from decreases in transport volumes, retention volumes and gross margins due to a less favorable natural gas price environment (decline in the average of natural gas spot prices), the cessation of certain long-term contracts, and lower basis differentials primarily between the West and East Texas hubs. The $640 million improvement in Interstate’s Segment Adjusted EBITDA in 2012 was driven by: 1) higher revenues (an increase of $662 million of which the consolidation of Southern Union’s transportation and storage businesses beginning March 26, 2012, accounts for $592 million); 2) greater contribution from unconsolidated affiliates higher (an increase of $251 million, primarily reflecting the acquisition of a 50% interest in Citrus); and offset by 3) a $273 million increase in expenses, primarily related to the Southern Union consolidation). The $49 million improvement in the Midstream’s segment Adjusted EBITDA in 2012 was driven by higher gross margins (up $181 million), offset by higher expenses ($122 million, primarily expenses related to the consolidation of Southern Union’s gathering and processing operations) and other items. However, $101 million of the gross margin improvement was non-fee based and resulted from a $125 million increase attributed to non fee-based contracts recorded in connection with the consolidation of Southern Union’s gathering and processing business from March 26, 2012 through December 31, 2012. The NGL Transportation and Services segment reflects the results from Lone Star JV which acquired the membership interests in LDH on May 2, 2011 (it also includes other wholly-owned or joint venture pipelines that have recently become operational). The $82 million improvement in the segment’s Adjusted EBITDA reflects twelve months of activity compared to only eight months of activity in 2011. Management noted it obtained control of Sunoco (including SXL) on October 5, 2012 and therefore provided no comparative results for the Sunoco Logistics segment. The $219 million adjusted EBITDA generated distributable cash flow of $154 million. ETP‘s share of cash distributions consists of its 2% general partner interest, its 32% limited partner interest and its IDRs. For the same reason cited in the paragraph above, no comparative results for the Retail Marketing segment were provided. But in a prior article discussing this acquisition, I noted that the EBITDA figure cited by management for 2011 was $261 million, on top of which $70 million in future synergies were expected over time. So the $109 million Adjusted EBIDTA achieved in 4Q12 seems excellent relative to prior expectations. Management noted gross margins were higher than traditionally seen and cautioned against extrapolating from 4Q12 results. Prior to 2012 the “All Other” segment consisted primarily of retail propane and other retail propane business. In 2012 this segment consisted primarily of: 1) the retail propane operations prior to their contribution of those operations to AmeriGas Partners, L.P. (“AmeriGas”) in January 2012 and the investment in AmeriGas for the balance of the year; 2) Southern Union’s local distribution operations beginning March 26, 2012; 3) the natural gas compression operations; and 4) Sunoco’s ~30% non-operating interest in a joint venture with The Carlyle Group, L.P. which owns a refinery in Philadelphia. In an article titled Distributable Cash Flow (“DCF”) I present the definition of DCF used by ETP and provide a comparison to definitions used by other MLPs. Using ETP’s definition, DCF for 2012 was $5.97 per unit ($1,488 million), up from $5.54 per unit ($1,153 million) for the comparable prior year period. As always, I first attempt to assess how these figures compare with what I call sustainable DCF for these periods and whether distributions were funded by additional debt or issuing additional units. The generic reasons why DCF as reported by the MLP may differs from call sustainable DCF are reviewed in an article titled “ Estimating sustainable DCF-why and how ”. Applying the method described there to ETP results generates the comparison outlined in Table 3 below: Period: 4Q12 4Q11 2012 2011 Net cash provided by operating activities 260 314 1,198 1,344 Less: Maintenance capital expenditures (143) (54) (313) (134) Less: Working capital (generated) - - - (166) Add: Distributions from unconsolidated affiliates in excess of cumulative earnings 35 6 130 22 Less: Net income attributable to noncontrolling interests - - (79) (28) Sustainable DCF 152 266 936 1,038 Add: Net income attributable to noncontrolling interests - - 79 28 Working capital used 535 29 475 - Risk management activities (56) 26 13 - Proceeds from sale of assets / disposal of liabilities 0 (8) - 11 Other (143) 6 (15) 76 DCF as reported 488 319 1,488 1,153 Table 3: Figures in $ Millions For 2012, the differences between reported DCF and sustainable DCF in 2012 relate to working capital. Under ETP’s definition, reported DCF always excludes working capital changes, whether positive or negative. My definition of sustainable DCF only excludes working capital generated (I deduct working capital consumed). Despite appearing to be inconsistent, this makes sense because in order to meet my definition of sustainability the MLP should generate enough capital to cover normal working capital needs. On the other hand, cash generated by the MLP through the liquidation or reduction of working capital is not a sustainable source and I therefore ignore it. Over reasonably lengthy measurement periods, working capital generated tends to be offset by needs to invest in working capital. Coverage ratios continue to be below 1.0 as indicated in Table 4 below: Period: 4Q12 4Q11 2012 2011 Distributions actually made 578 321 1,576 1,203 Reported DCF 488 319 1,488 1,153 Sustainable DCF 152 266 936 1,038 Coverage ratio based on reported DCF 0.84 1.00 0.94 0.96 Coverage ratio based on sustainable DCF 0.26 0.83 0.59 0.86 Table 4 As seen in Table 3, the large investment in working capital accounts for the bulk of the difference between coverage based on reported vs. sustainable DCF shown in Table 4. The ratios will converge in future periods if further investments in working capital are not required. I find it helpful to look at a simplified cash flow statement by netting certain items (e.g., acquisitions against dispositions) and by separating cash generation from cash consumption. Here is what I see for ETP: Simplified Sources and Uses of Funds Period: 4Q12 4Q11 2012 2011 Net cash from operations, less maintenance capex, net income from non-controlling interests, & distributions (461) (61) (691) - Capital expenditures ex maintenance & net of proceeds from sale of PP&E (900) (411) (2,527) (1,282) Acquisitions, investments (net of sale proceeds) 754 3 304 (1,962) Debt incurred (repaid) - (262) - - Other CF from financing activities, net (2) (8) (20) (20) (608) (738) (2,934) (3,264) Net cash from operations, less maintenance capex, net income from non-controlling interests, & distributions - - - 7 Cash contributions/distributions related to affiliates & noncontrolling interests 87 34 420 445 Debt incurred (repaid) 580 - 1,776 1,377 Partnership units  issued (retired) 19 668 791 1,467 Other CF from investing activities, net 123 7 151 25 809 709 3,138 3,321 Net change in cash 200 (30) 204 57 Table 5: Figures in $ Millions Net cash from operations, less maintenance capital expenditures, less net income from non-controlling interests fell short of covering distributions by $691 million in 2012. However, some distributions from unconsolidated affiliates appear in the cash flow statement as cash from affiliates and non-controlling interests (e.g., RGP’s contribution to the Lone Star JV totaled $320 million in 2012). Those items totaled $420 million in 2012 and if I reclassify them to cash from operations the shortfall is reduced to $271 million. Still, in 2012 ETP funded a portion of its distributions (I estimate ~17%) by issuing equity, debt and/or using proceeds from asset dispositions. However, it is difficult to draw conclusions due to all the “noise” in the 2012 financials and the fact that large acquisitions were made during 2012 but their results are included on a partial year basis (from the date they were acquired). A pro forma analysis of what the 2012 income statement would have looked like had the Sunoco and Holdco transactions occurred on January 1, 2012 is provided below: Pro Forma Financials ETP Historical ETP Historical excluding Propane Sunoco Historical Southern Union Historical Holdco Pro Forma Adj. Pro Forma Revenues 15,702 15,609 35,258 443 (12,174) 39,136 Cost of products sold – natural gas operations 13,166 13,086 33,142 302 (11,193) 35,337 Depreciation and amortization 656 652 168 49 76 945 Selling, general and administrative 486 485 459 11 (119) 836 Impairment charges - – 124 - (22) 102 Total costs & expenses 14,308 14,223 33,893 362 11,258) 37,220 Operating income 1,394 1,386 1,365 81 (916) 1,916 Interest expense, net of interest capitalized (665) (689) (123) (50) 2 (860) Equity in earnings of affiliates 142 161 41 16 5 223 Gain on formation of PA refinery entity - – 1,144 - (1,144) – Other, net 11 9 118 (2) (2) 127 Pre-tax income from continuing operations 1,820 867 2,545 45 (2,055) 1,402 Table 6: Figures in $ Millions The sale of the retail propane business to APU occurred on January 12, 2012. Therefore the relevant columns to compare in Table 6 are the 3 rd (ETP Historical excluding Propane) and the last (Pro Forma). On a pro forma basis pre-tax income would have increased by ~62% while the number of units outstanding increased by ~40%. ETP’s current yield is at the high end of the MLP universe. A comparison to some of the MLPs I follow is provided in Table 7 below: As of 3/16/13: Price Quarterly Distribution Yield Magellan Midstream Partners (MMP) $49.46 $0.50000 4.04% Plains All American Pipeline (PAA) $54.07 $0.56250 4.16% Enterprise Products Partners (EPD) $56.40 $0.66000 4.68% Kinder Morgan Energy Partners (KMP) $86.56 $1.29000 5.96% El Paso Pipeline Partners (EPB) $40.69 $0.61000 6.00% Inergy (NRGY) $19.27 $0.29000 6.02% Targa Resources Partners (NGLS) $42.70 $0.68000 6.37% Williams Partners (WPZ) $49.37 $0.82750 6.70% Buckeye Partners (BPL) $58.35 $1.03750 7.11% Energy Transfer Partners (ETP) $47.21 $0.89375 7.57% Boardwalk Pipeline Partners (BWP) $27.75 $0.53250 7.68% Regency Energy Partners (RGP) $23.68 $0.46000 7.77% Suburban Propane Partners (SPH) $43.09 $0.87500 8.12% Table 7 My concerns regarding ETP revolve around: 1) lack if distribution growth and the inadequate distribution coverage; 2) the structural complexities; 3) the high burden created by the IDRs (notwithstanding temporary waivers and reductions by ETE): 4) the challenges of integrating the operations acquired and selling portions deemed non-core (e.g., sale of Southern Union’s utility operations to Laclede Group); 5) the decision to retain the Sunoco retail operation despite a lack of fit and no announcement as to a solution that would eliminate the tax inefficiencies; and 6) the need to face additional, significant non-arms length transactions as management seeks to simplify the organization, a process it acknowledges may take two years. An example of the latter is Holdco’s sale of Southern Union Gas Services, Ltd. (SUGS), to RGP for $1.5 billion. Management previously stated it is contemplating folding RGP into ETP, which would be another complex related-party transaction. These concerns previously led me to reduce my ETP position. I have not reduced it further and have retained my ETE position..
    Wise Analysis
    A Closer Look at Plains All American Pipeline’s Distributable Cash Flow as of 4Q 2012
  • by , 1 years ago
  • tags: PAA NRGY BPL SPH
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool On February 27, 2013, Plains All American Pipeline L.P. (PAA) provided its 2012 annual report on Form 10-K. Results compared favorably to the prior year and to management’s guidance. Revenues, operating income, net income and earnings before interest, depreciation & amortization and income tax expenses (EBITDA) are summarized in Table 1: Period: 4Q12 4Q11 2012 2011 2010 Revenues 9,439 8,884 37,797 34,275 25,893 Operating income 402 359 1,425 1,298 767 Net income 330 288 1,127 994 514 EBITDA 541 426 1,951 1,541 1,017 Adjusted EBITDA 610 471 2,107 1,598 1,106 Weighted avg. units o/s (million) 337 308 328 299 275 Table 1: Figures in $ Millions On 11/5/12, the mid-point of the Adjusted EBITDA guidance for 2012 was $2,017 million, a ~7% increase vs. the guidance provided on 8/6/12 and ~22% over the full year guidance provided at the beginning of the year. On that date the preliminary Adjusted EBITDA guidance for 2013 was $1,925 million (mid-point). On 2/6/13 PAA increased its 2013 guidance to $1,976 million, but still a number lower than what was achieved in 2012. This is because management is operating on the assumption that 2012 was a year in which market conditions were extremely favorable for the Supply and Logistics segment, and that 2013 will see a “a return to baseline” after 1Q13. Strong performance was exhibited by all segments, as seen in Table 2: Period: 4Q12 4Q11 2012 2011 2010 Transportation segment profit 194 139 710 555 516 Facilities segment profit 138 99 482 358 270 Supply & Logistics segment profit 209 183 753 647 240 Total segment profit 541 421 1,945 1,560 1,026 Depreciation and amortization (126) (58) (482) (249) (256) Interest expense (74) (63) (288) (253) (248) Other income/(expense), net - 5 6 (19) (9) Income tax benefit/(expense) (11) (17) (54) (45) 1 Net income 330 288 1,084 994 514 Less: Net income attributable to noncontrolling interests (10) (10) (33) (28) (9) Net income attributable to PAA 320 278 1,051 966 505 Table 2: Figures in $ Millions In 3Q12 PAA decided not to proceed with the Pier 400 project and wrote down a substantial portion of its investment in it. The write down amounted to ~$125 million and is reflected in Table 2 as an increase to depreciation & amortization. Hence the large increase in this line item in 2012 vs. the prior year periods. The Pier 400 terminal project involved development of a deepwater petroleum import terminal at Pier 400 and Terminal Island in the Port of Los Angeles for the purpose of handling marine receipts of crude oil and refinery feedstock. Unlike the Facilities and Transportation segments which are predominantly fee based businesses, Supply & Logistics is margin based and hence its results are more volatile. This segment has benefited from higher volumes and higher margins. Increased drilling activities and increased production of oil and natural gas liquids (“NGL”) in the areas it services (Bakken, Eagle Ford, West Texas, Western Oklahoma and Texas Panhandle) drove higher volumes. Margins were driven higher because production volumes exceed existing pipeline takeaway capacity in these regions, so customers will pay more to whoever can get their products to markets. Supply-demand imbalances also increased the volatility of historical differentials for various grades of crude oil and also impacted the historical pricing relationship between NGL and crude oil. Market conditions in 2011 and 2012 were thus highly favorable to the Supply & Logistics segment. Management is being appropriately cautious in assuming that these conditions may not be repeated in 2013. In an article titled Distributable Cash Flow (“DCF”) I present the definition of DCF used by Plains All American Pipeline L.P. (PAA) and provide a comparison to definitions used by other master limited partnerships. Using PAA’s definition, DCF in 2012 was $1,550 million ($4.73 per unit), up from $1,149 million ($3.84 per unit) in 2011. As always, I first attempt to assess how these figures compare with what I call sustainable DCF for these periods and whether distributions were funded by additional debt or issuing additional units. The generic reasons why DCF as reported by the MLP may differ from sustainable DCF are reviewed in an article titled Estimating Sustainable DCF-Why and How . Applying the method described there to PAA’s results through 12/31/12 generates the comparison outlined in Table 3 below: Period: 4Q12 4Q11 2012 2011 Net cash provided by operating activities 360 613 1,240 2,365 Less: Maintenance capital expenditures (47) (43) (170) (120) Less: Working capital (generated) - (217) - (1,002) Less: risk management gains (losses) Less: net income attributable to GP Less: Net income attributable to noncontrolling interests (10) (10) (33) (28) Sustainable DCF 303 343 1,037 1,215 Add: Net income attributable to noncontrolling interests 10 10 33 28 Working capital used 13 - 466 - Risk management activities 148 13 193 (67) Proceeds from sale of assets / disposal of liabilities 3 8 33 54 Other (21) (32) (212) (81) DCF as reported 456 343 1,550 1,149 Table 3: Figures in $ Millions The principal differences between reported DCF and sustainable DCF relate working capital, risk management activities and a variety of items grouped under “Other”. Under PAA’s definition, reported DCF always excludes working capital changes, whether positive or negative. My definition of sustainable DCF only excludes working capital generated (I deduct working capital consumed). Despite appearing to be inconsistent, this makes sense because in order to meet my definition of sustainability the MLP should generate enough capital to cover normal working capital needs. On the other hand, cash generated by the MLP through the liquidation or reduction of working capital is not a sustainable source and I therefore ignore it. Over reasonably lengthy measurement periods, working capital generated tends to be offset by needs to invest in working capital. A good example of this is provided by the working capital lines for 2011 and 2012 in Table 3. In 2012 working capital consumed cash principally due to an increase in crude oil inventories, while in 2011 crude oil inventories were liquidated and thus generated a very significant amount of cash. Overall, in 2012 working capital consumed cash amounting to $466 million. Management adds back this amount in deriving reported DCF while I do not. The $193 million adjustment for risk management activities in 2012 consists primarily of foreign currency adjustments and losses from derivative activities. Management adds back these losses in calculating reported DCF. I do not do so when calculating sustainable DCF. The $212 million adjustment for “Other” items in 2012 consists of non-cash compensation, losses on inventory valuation adjustments, and distributions in excess of earnings from unconsolidated investments. Again, management adds back these items in calculating reported DCF. I do not do so when calculating sustainable DCF. PAA increased DCF guidance for 2012 to a mid-point of $1,437 million (up from $1,352 million guidance provided last November), but still lower than 2012 reported DCF for the same reasons outlined in the discussion of Table 1. As seen in Table 3, the differences between reported and sustainable DCF can be pronounced. This, of course, impacts coverage ratios, as indicated in Table 4 below: Period: 4Q12 4Q11 2012 2011 Distributions actually made 259 207 969 791 Reported DCF 456 343 1,550 1,149 Sustainable DCF 303 343 1,037 1,215 Coverage ratio based on reported DCF 1.76 1.66 1.60 1.45 Coverage ratio based on sustainable DCF 1.17 1.66 1.07 1.54 Table 4: $ millions, except coverage ratios I find it helpful to look at a simplified cash flow statement by netting certain items (e.g., acquisitions against dispositions) and by separating cash generation from cash consumption. Here is what I see for PAA: Simplified Sources and Uses of Funds Period: 4Q12 4Q11 2012 2011 Net cash from operations, less maintenance capex, net income from non-controlling interests, & distributions - - - - Capital expenditures ex maintenance & net of proceeds from sale of PP&E (245) (136) (953) (503) Acquisitions, investments (net of sale proceeds) (750) (632) (2,232) (1,000) Debt incurred (repaid) - - - (759) Other CF from investing activities, net - (19) (37) (27) Other CF from financing activities, net (9) (12) (19) (24) (1,004) (799) (3,241) (2,313) Net cash from operations, less maintenance capex, net income from non-controlling interests, & distributions 54 363 101 1,454 Cash contributions/distributions related to affiliates & noncontrolling interests (12) (12) (48) (40) Debt incurred (repaid) 761 79 2,207 - Partnership units  issued (retired) 167 386 979 889 Other CF from investing activities, net 26 - - - 996 816 3,239 2,303 Net change in cash (8) 17 (2) (10) Table 5: Figures in $ Millions Net cash from operations, less maintenance capital expenditures, less cash related to net income attributable to non-controlling partners exceeded distributions by $101 million in 2012 and by $1,454 million in 2011. The large difference between the excess in these two years is due to changes in crude oil inventories (increase in 2012, decrease in 2011, as explained in the discussion of Table 3). Clearly PAA is not using cash raised from issuance of debt and equity to fund distributions. Over the past 5 years (2008-2012) net cash from operations generated a cumulative excess of ~$962 million (after deducting maintenance capital expenditures, net income from non-controlling interests, and distributions). Such excesses constitute significant sources of capital for PAA and reduce reliance on debt or issuance of additional units that dilute existing holders. This is of particular importance to PAA limited partners because issuing new units is very expensive due to the general partner’s incentive distribution rights (“IDR”). The IDRs entitle the general partner to 48% of amounts distributed in excess of $0.3375 per unit. Therefore at the current distribution rate of $0.5625 per quarter, each additional unit issued consumes ~$0.88 of DCF per quarter. This is a heavy burden that pushes up PAA’s cost of capital. The excess cash flow has a very low cost of capital compared to the cost of issuing additional units. PAA’s current yield is at the low end of the MLP universe. A comparison to some of the MLPs I follow is provided in Table 6 below: As of 3/11/13: Price Quarterly Distribution Yield Magellan Midstream Partners (MMP) $50.05 $0.50000 4.00% Plains All American Pipeline (PAA) $54.42 $0.56250 4.13% Enterprise Products Partners (EPD) $57.54 $0.66000 4.59% Inergy (NRGY) $20.33 $0.29000 5.71% El Paso Pipeline Partners (EPB) $41.99 $0.61000 5.81% Kinder Morgan Energy Partners (KMP) $85.86 $1.29000 6.01% Targa Resources Partners (NGLS) $43.98 $0.68000 6.18% Williams Partners (WPZ) $49.05 $0.82750 6.75% Buckeye Partners (BPL) $59.23 $1.03750 7.01% Energy Transfer Partners (ETP) $47.32 $0.89375 7.55% Regency Energy Partners (RGP) $24.03 $0.46000 7.66% Boardwalk Pipeline Partners (BWP) $27.40 $0.53250 7.77% Suburban Propane Partners (SPH) $42.68 $0.87500 8.20% Table 6 PAA, EPD and MMP are all outstanding MLPs. The relatively low yields notwithstanding, their operational results have been excellent and have driven up unit prices, thus generating significant capital gains for the partners. They are a solid choice for more conservative MLP investors. My concerns with PAA revolve around capital structure and the sharper run-up in its unit price. From a capital structure standpoint, EPD and MMP are not burdened by IDRs while PAA pays 48% at the margin. While the IDR burden is less of an issue with respect to organic growth (because of the low ratio of required investment to the expected cash flow it will generate), it is a major factor in large acquisitions which, under current market conditions, command high multiples and require lengthy time periods to generate the projected synergies. From a price per unit standpoint, year-to-date PAA’s unit price is up ~20% vs. 15% for EPD and ~16% for MMP.
    Wise Analysis
    A Closer Look at Williams Partners’ Distributable Cash Flow as of 4Q 2012
  • by , 1 years ago
  • tags: WPZ MMP KMP EPD
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool On February 27, 2013, Williams Partners, L.P. (WPZ) provided its 2012 annual report on Form 10-K. Results compared unfavorably to the prior year and even to the most recent guidance. In what is becoming an unwelcome routine, management again lowered Distributable Cash Flow (“DCF”) guidance for 2013-2014, as indicated in Table 1 below: Guidance as of: 2/20/2013 10/31/2012 7/23/2012 4/23/2012 Midpoint DCF Actual 2012 2012 $1,489 $1,500 $1,550 $1,725 2013 $1,800 $2,075 $1,900 $2,150 2014 $2,475 $2,700 $2,265 $2,275 Midpoint DCF coverage 2012 0.95 0.95 1.00 1.14 2013 0.89 1.02 1.03 1.21 2014 1.01 1.12 1.05 1.11 Table 1 ($ millions except coverage ratios In November 2012, WPZ completed the $2.36 billion acquisition of an 83.3% interest in the Geismar Olefins-Production Facility from Williams Companies, Inc. (WMB) and issued WMB ~42.8 million units to pay for this acquisition (i.e., virtually an all equity deal). WMB is WPZ’s general partner and, following the Geismar acquisition, owns a ~68% limited partner interest, a 2% general partner interest and incentive distribution rights (“IDRs”). Located south of Baton Rouge, Louisiana, the Geismar facility is a light-end NGL cracker with current volumes of 39,000 barrels per day (bpd) of ethane and 3,000 bpd of propane and annual production of 1.35 billion pounds of ethylene. With the benefit of an expansion under way and scheduled for completion by late 2013, the facility’s annual ethylene production capacity will grow by 600 million pounds to 1.95 billion pounds. Since the owner of the remaining ownership interest in the facility is not participating in the expansion, WPZ’s overall undivided interest following the expansion will be ~ 88%. The Geismar acquisition is expected to bring more certainty to cash flows that are currently exposed to volatile ethane prices by shifting the commodity price exposure to ethylene. The transaction reduces WPZ’s ethane exposure by 70% in 2013 and fully eliminates it by 2014 (when WPZ will effectively be short ethane). The Geismar dropdown contributed $42 million of DCF in the first two months following the acquisition (Nov-Dec). My back-of-the-envelope calculation annualizes to ~$250 million per annum, or $360 million with a ~44% capacity expansion. This is probably way too rough an estimate, but I will closely watch Geismar contributions in future periods because there is a significant gap between my number and management’s 2014 estimate of $570 million in segment profit plus depreciation and amortization. Ethane exposure contributed significantly to the poor 2012 results. The sharp decline  in prices (down 46% in 4Q12) for natural gas liquids (“NGL”) reduced processing margins, led to ethane rejection and thus generated lower equity volumes under keep-whole agreements and percent-of-liquids arrangements.  WPZ’s Midstream segment provides natural gas gathering and processing services under fee contracts (volumetric-based), keep-whole agreements and percent-of-liquids arrangements. A glossary of terms provides further explanations of these terms and of ethane rejection. Under keep-whole and percent-of-liquid processing contracts, the Midstream segment retains the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream (these are the equity volumes referred to above). It recognizes revenues when the extracted NGLs are sold and delivered. Lower NGL prices coupled with lower volumes produce lower revenues, as well as sharply lower operating income and net income, as seen in Table 2 below: Period: 4Q12 4Q11 2012 2011 2010 Revenues 1,849 2,045 7,351 7,714 6,459 Operating income 364 471 1,517 1,775 1,427 Net income 291 412 1,232 1,511 1,188 EBITDA 581 668 2,348 2,545 2,116 Net income per common unit 0.42 1.05 1.89 3.69 2.66 Weighted avg. units o/s (million) 382 290 342 290 214   Table 2: Figures in $ Millions (except net income per unit and units outstanding) I have not analyzed results by segment because, beginning November 2012, operations related to the Geismar acquisition (manufacture of olefin products) were incorporated in what was known as the Midstream segment and revenues began to be broken down differently than they were before (into service revenues and product sales). Costs and operating expenses also began being categorized differently than they were in the past. Furthermore, management implemented a new structure, effective January 1, 2013, that reorganizes the businesses into geographically based operational areas, as set forth below in WPZ’s Form 10-K for 2012:   I expect the new segment reporting format will be reflected in the 1Q13 report. The numbers reported by WPZ and appearing in Table 2 have been recast for the Geismar acquisition. As a result, net income increased by $185 million, $133 million and $87 million for the years ended 2012, 2011, and 2010, respectively. Earnings per unit and DCF were not impacted as pre-acquisition earnings and cash flows were allocated to WMB. In an article titled Distributable Cash Flow (“DCF”) I present the definition of DCF used by WPZ and provide a comparison to definitions used by other master limited partnerships (“MLPs”). Using WPZ’s definition, DCF for the trailing twelve month (“TTM”) period ending 12/31/12 was $1,489 million ($4.35 per unit), down from $1,650 in the comparable prior year period ($5.68 per unit). As always, I first attempt to assess how these figures compare with what I call sustainable DCF for these periods and whether distributions were funded by additional debt or issuing additional units. The generic reasons why DCF as reported by the MLP may differ from what I call sustainable DCF are reviewed in an article titled Estimating Sustainable DCF-Why and How . Applying the method described there to WPZ results through 12/31/12 generates the comparison outlined in Table 3 below: Period: 4Q12 4Q11 2012 2011 Net cash provided by operating activities 525 661 2,018 2,290 Less: Maintenance capital expenditures (103) (127) (407) (421) Less: Working capital (generated) (23) (87) (72) (158) Less: net income attributable to GP (20) (22) (192) (136) Sustainable DCF 379 425 1,347 1,575 Other 26 19 142 75 DCF as reported 405 444 1,489 1,650 Table 3: Figures in $ Millions The gap between reported DCF and sustainable DCF shown under “other” is comprised principally items that management adds back in deriving reported DCF. These include acquisition-related and reorganization-related costs, certain reimbursements from WMB and the excess cash flow over earnings from WPZ’s equity investments. But overall, the differences between reported and sustainable DCF are not huge. Despite the deterioration in key performance parameters, WPZ increased 4Q12 distribution to $0.8275 per unit (up 2.5% from $0.8075 in 3Q12 and up 8.5% from $0.7625 in 4Q11). Coverage ratios in Table 4 below are therefore shown based on actual distributions made (e.g., the distribution announced for 3Q12 was actually made in 4Q12) and based on declared distributions (e.g., assuming the distribution declared 4Q12 was made in 4Q12): Period: 4Q12 4Q11 2012 2011 Distributions declared 442 311 1,571 1,167 Distributions actually made (1 quarter lag) 394 294 1,440 1,124 Reported DCF 405 444 1,489 1,650 Sustainable DCF 379 425 1,347 1,575 Coverage ratio based on reported DCF Based on distributions declared 0.92 1.43 0.95 1.41 Based on distributions actually made 1.03 1.51 1.03 1.47 Coverage ratio based on sustainable DCF Based on distributions declared 0.86 1.37 0.86 1.35 Based on distributions actually made 0.96 1.45 0.94 1.40 Table 4: $ millions, except coverage ratios The sharply lower coverage ratios reflect the decline in NGL prices and, to a lesser extent, higher G&A expenses. While I did not anticipate the decline in NGL prices, I did mention in a prior article (dated May 24, 2012) the risk of lower coverage ratios resulting from the rapid growth in the number of units outstanding as a result of issuing equity to partially finance large drop-down acquisitions.  Indeed, this has been a major contributing factor as can be seen in Table 2. The number of units outstanding has increased 31% from 4Q11. Management expects coverage ratios will remain negative (below 1) in 2013 and to just cover distributions in 2014 (see Table 1). The assumptions regarding how many additional limited partner units management expects to issue in 2013-2014 have not been disclosed. I am not comfortable with the practice of increasing distributions in the face of declining coverage and believe unitholders would be better off seeing distributions held steady and fewer shares being issued. It is helpful to look at a simplified cash flow statement by netting certain items (e.g., acquisitions against dispositions) and by separating cash generation from cash consumption. Here is what I see for WPZ: Simplified Sources and Uses of Funds Period: 4Q12 4Q11 2012 2011 Capital expenditures ex maintenance & net of proceeds from sale of PP&E (721) (275) (1,683) (579) Acquisitions, investments (net of sale proceeds) (205) (52) (2,536) (520) Other CF from investing activities, net (5) (5) - - Other CF from financing activities, net - (100) - (98) (931) (432) (4,219) (1,197) Net cash from operations, less maintenance capex, net income from non-controlling interests, & distributions 28 240 171 745 Cash contributions/distributions related to affiliates & noncontrolling interests 5 31 93 31 Debt incurred (repaid) 374 85 1,187 396 Partnership units  issued (retired) - (16) 2,559 - Other CF from investing activities, net - - 53 1 Other CF from financing activities, net 13 - 13 - 420 340 4,076 1,173 Net change in cash (511) (92) (143) (24) Table 5: Figures in $ Millions Net cash from operations, less maintenance capital expenditures, less cash related to net income attributable to non-partners exceeded distributions by $171 million in 2012 and by $745 million in 2011. In 4Q12 the excess was minimal and, since these numbers reflect distributions actually made rather than declared, I expect a shortfall in the current quarter (as was the case in 3Q12). This will indicate that distributions are being funded through the issuance of additional equity. Management expects this to continue in 2013. Given that poor operational performance has been coupled with an unrelenting pace of equity issuances ($490 million in 1Q12, $1,581 million in 2Q12, $488 million in 3Q12 and ~$635 million so far in 1Q13), it is not surprising that the price per unit has languished and is down ~18% from ~$60 on December 30, 2011 to $49.10 as of 3/8/13). Table 5 shows there has also been a significant increase in debt. WPZ ended 2012 with long term debt at ~3.6x EBITDA, an increase over the ~2.8x multiple at the end of 2011. Although this level does not appear to be excessive, it could move higher even absent debt issuances should EBITDA levels continue to decline. Planned capital investments for 2013 total ~$ 3.4 billion (excluding maintenance expenditures), virtually all of which will need to be funded through debt and equity issuances. There could therefore be additional pressure on unit prices. Of the MLPs I follow, WPZ has the third largest market capitalization (after EPD and KMP). Its cost of capital is much higher than that of EPD, among other reasons due to WMB’s IDRs. KMP is also burdened with a higher cost of capital due to its structure. I prefer WPZ to KMP because I think it has superior growth opportunities and presents better value at these price levels. A comparison of WPZ’s yield to that of the other MLPs I follow is presented in Table 6 below: As of 3/8/13: Price Quarterly Distribution Yield Magellan Midstream Partners (MMP) $50.12 $0.50000 3.99% Plains All American Pipeline (PAA) $54.34 $0.56250 4.14% Enterprise Products Partners (EPD) $57.75 $0.66000 4.57% Inergy (NRGY) $20.30 $0.29000 5.71% El Paso Pipeline Partners (EPB) $41.88 $0.61000 5.83% Kinder Morgan Energy Partners (KMP) $85.41 $1.29000 6.04% Targa Resources Partners (NGLS) $43.92 $0.68000 6.19% Williams Partners (WPZ) $49.10 $0.82750 6.74% Buckeye Partners (BPL) $59.18 $1.03750 7.01% Energy Transfer Partners (ETP) $47.10 $0.89375 7.59% Regency Energy Partners (RGP) $24.19 $0.46000 7.61% Boardwalk Pipeline Partners (BWP) $27.34 $0.53250 7.79% Suburban Propane Partners (SPH) $42.66 $0.87500 8.20% Table 6 Despite the recent signs of weakness I have been adding to my WPZ position on pullbacks (and initiated a position in WMB) for the following reasons: 1) Low natural gas prices are incorporated into the 203-2014 guidance numbers; 2) while the Caiman Eastern acquisition will require ~$1.34 billion in capital expenditures from 2012-2014, management projects segment profit plus depreciation and amortization in 2014 to more than double the 2013 level and exceed $400 million; 3) the benefits of the Geismar facility expansion currently under way are projected to be very significant. Management estimates segment profit plus depreciation and amortization in 2014 (the first year of post-expansion operations) to total $570 million, a modest 4.4 multiple of the purchase price plus the additional $270 million of post-closing capital expenditures; and 5) between 2012 and 2014 WPZ will have invested ~$12 billion in growth capital, ~$6.3 billion of which is in the Marcellus and Utica shales. Management projects fee-based revenues will increase to ~77% of business by 2014 (from 68% in 2012). Management has, in the past, consistently run significant excess DCF coverage. Its decision to significantly dilute unitholders in executing two transformative transactions, in conjunction with an adverse NGL pricing environment, has turned the excess into a shortfall. Unit price has declined significantly and presents a buying opportunity for investors whose faith in management is intact and who are willing to wait until 2014 when results will show whether such faith was justified. But I allocate less to WPZ/WMB than to EPD, EPB or PAA.
    Wise Analysis
    A Closer Look at Enterprise Products Partners' Distributable Cash Flow as of 4Q 2012
  • by , 1 years ago
  • tags: MMP PAA EPD NRGY
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool On March 1, 2013, Enterprise Products Partners L.P. (EPD) provided its 2012 annual report on Form 10-K. Revenues, operating income, net income and earnings before interest, depreciation & amortization and income tax expenses (EBITDA) are summarized in Table 1: Period: 4Q12 4Q11 2012 2011 2010 Operating revenues 11,014 11,586 42,583 44,313 33,739 Operating income 823 909 3,109 2,859 2,147 Net income 617 726 2,428 2,088 1,384 EBITDA 1,110 1,178 4,288 3,867 3,137 Adjusted EBITDA 1,132 1,198 4,330 3,960 3,256 Weighted avg. units o/s (million) 903 879 893 860 279 Table 1: Figures in $ Millions, except weighted average units outstanding Fluctuations in revenues and cost of sales amounts are explained in large part by changes in energy commodity prices, especially those for natural gas liquids (“NGL”), natural gas and crude oil. Energy commodity prices in 2012 were lower than they were in 2011 (by ~23% for NGLs, by ~31% for natural gas, and by ~1% for crude oil). Therefore, with one exception, segment revenues in 4Q12 and 2012 were down vs. the prior year periods, as seen in Table 2: Period: 4Q12 4Q11 2012 2011 2010 NGL Pipelines Services 4,090 4,771 15,168 17,483 14,203 Onshore Natural Gas Pipelines Services 952 964 3,353 3,730 3,702 Onshore Crude Oil Pipelines Services 4,494 4,452 17,662 16,061 10,795 Offshore Pipelines Services 41 68 192 256 311 Petrochemical  Refined Products Services 1,495 1,331 6,209 6,782 4,730 Total consolidated revenues 11,072 11,586 42,583 44,313 33,739 Table 2: Figures in $ Millions However, lower revenues resulting from decreases in NGL, natural gas, crude oil and petrochemical prices were more than offset by lower costs of sales attributable to these decreases,  hence, with one exception, the significant and impressive improvement in gross operating margins, as seen in Table 3 below: Period: 4Q12 4Q11 2012 2011 2010 NGL Pipelines Services 632 635 2,469 2,184 1,733 Onshore Natural Gas Pipelines Services 210 199 776 675 527 Onshore Crude Oil Pipelines Services 135 67 388 234 114 Offshore Pipelines Services 42 60 173 228 298 Petrochemical  Refined Products Services 143 137 580 535 585 Other investments - 4 2 15 (3) Total segment gross operating margin 1,162 1,101 4,387 3,872 3,253 Table 3: Figures in $ Millions The Offshore Pipeline Services segment underperformed in 2012 and is expected to continue to decline in 2013 because natural gas producers are switching more of their resources to increasing crude oil production (both onshore and offshore) and to increasing onshore NGL-rich natural gas production. EPD estimates average volumes on its largest offshore natural gas asset, the Independence Hub platform (80% owned by EPD), will approximate only 100 MMcf/d during 2013, a sharp decline from an average of 313 MMcf/d and 455 MMcf/d during 2012 and 2011, respectively.  This will, hopefully, be somewhat offset by a recovery in crude oil volumes handled by EPB’s offshore Gulf of Mexico assets in 2013 from the lower volumes experienced since 2010. Total segment gross operating margin in Table 3 above is defined by EPD as operating income before: (1) depreciation, amortization and accretion expenses; (2) non−cash asset impairment charges; (3) operating lease expenses for which it did not have the payment obligation; (4) gains and losses from sales of assets and investments; and (5) general and administrative costs. In an article titled Distributable Cash Flow (“DCF”) I present the definition of DCF used by EPD and provide a comparison to definitions used by other master limited partnerships (“MLPs”). Using EPD’s definition, DCF for the trailing twelve month (“TTM”) period ending 12/31/12 was $4,133 million ($4.63 per unit), up from $3,737 in the comparable prior year period ($4.35 per unit). As always, I first attempt to assess how these figures compare with what I call sustainable DCF for these periods and whether distributions were funded by additional debt or issuing additional units. The generic reasons why DCF as reported by the MLP may differ from what I call sustainable DCF are reviewed in an article titled Estimating Sustainable DCF-Why and How . Applying the method described there to EPD results through 12/31/12 generates the comparison outlined in Table 4 below: Period: 4Q12 4Q11 2012 2011 Net cash provided by operating activities 1,275 1,102 3,331 2,300 Less: Maintenance capital expenditures (84) (79) (296) (240) Less: Working capital (generated) (328) (205) (267) - Less: risk management gains (losses)     Less: net income attributable to GP     Less: Net income attributable to noncontrolling interests - (5) (4) (63) Sustainable DCF 864 814 2,726 1,997 Add: Net income attributable to noncontrolling interests - 5 41 63 Working capital used - - - 202 Risk management activities - - (23) 7 Proceeds from sale of assets / disposal of liabilities 31 613 1,037 106 Other (9) (2) (45) (118) DCF as reported 886 1,429 3,737 2,256 Table 4: Figures in $ Millions The principal differences between reported DCF and sustainable DCF relate working capital (in 2011) and to proceeds from asset sales. In deriving reported DCF for 2011 management added back to net cash from operations $202 million of working capital used. Under EPD’s definition, reported DCF always excludes working capital changes, whether positive or negative. In contrast, as detailed in my prior articles, in deriving sustainable DCF I generally do not add back working capital used but, on the other hand, I exclude working capital generated. Despite appearing to be inconsistent, this makes sense because in order to meet my definition of sustainability the master limited partnerships should, on the one hand, generate enough capital to cover normal working capital needs. On the other hand, cash generated from working capital is not a sustainable source and I therefore ignore it. Over reasonably lengthy measurement periods, working capital generated tends to be offset by needs to invest in working capital. I therefore do not add working capital consumed to net cash provided by operating activities in deriving sustainable DCF. Also, in deriving its reported DCF, EPD adds back proceeds from asset sales. In the TTM ending 12/31/12 these totaled $1,037 million, the largest component of which was generated by the sale of 29 million units of Energy Transfer Equity, LP (ETE) for $1,095 million between January and April, 2012. As readers of my prior articles are aware, I do not include proceeds from asset sales in my calculation of sustainable DCF. Coverage ratios appear strong, and coverage was particularly impressive in 4Q12, as indicated in Table 5 below: Period: 4Q12 4Q11 2012 2011 Distributions to unitholders ($ Millions) 567 523 2,192 2,035 Reported DCF per unit $0.98 $1.63 $4.63 $4.35 Sustainable DCF per unit $0.96 $0.93 $2.83 $3.17 Coverage ratio based on reported DCF 1.56 2.73 1.89 1.84 Coverage ratio based on sustainable DCF 1.52 1.55 1.15 1.34 Table 5 I find it helpful to look at a simplified cash flow statement by netting certain items (e.g., acquisitions against dispositions) and by separating cash generation from cash consumption. Here is what I see for EPD: Simplified Sources and Uses of Funds Period: 4Q12 4Q11 2012 2011 Capital expenditures ex maintenance & net of proceeds from sale of PP&E (822) (997) (3,256) (3,571) Acquisitions, investments (net of sale proceeds) 31 593 1,199 1,034 Debt incurred (repaid) - (628) - - Other CF from investing activities, net (249) - (596) - Other CF from financing activities, net (5) (1) (173) (29)   (1,045) (1,032) (2,825) (2,566)       Net cash from operations, less maintenance capex, net income from non-controlling interests, & distributions 624 500 333 999 Cash contributions/distributions related to affiliates & noncontrolling interests 0 4 7 9 Debt incurred (repaid) 261 - 1,665 914 Partnership units  issued (retired) 162 476 817 543 Other CF from investing activities, net - 43 - 56   1,047 1,023 2,821 2,520 Net change in cash 2 (9) (4) (46) Table 6: Figures in $ Millions Net cash from operations, less maintenance capital expenditures, less cash related to net income attributable to non-controlling interests exceeded distributions by $333 million in the TTM ending 12/31/12 and by $999 million in the comparable prior year period. EPD is not using cash raised from issuance of debt and equity to fund distributions. The excess enables EPD to reduce reliance on the issuance of additional partnership units or debt to fund expansion projects. EPD stated early in 2012 that it does not expect to be issuing equity in 2012. I nevertheless said in a prior article that I expect to see additional units issued by the end of 2012 in light of the increase in capital expenditure in 2012 and what’s coming up in 2013. While I was off somewhat on the timing (the issuance occurred on 2/5/13), I was pleased with the relatively modest number of EPD units issued (9.2 million, ~1% dilution). The issue was priced at $54.56 per unit and generated net cash proceeds of $486.6 million. The prior issuance of units occurred in September 2012 when EPD issued 10.4 million units at $53.07 per unit and generated total net cash proceeds of $473.3 million. Overall, major capital projects in which EPD had invested $2.9 billion were completed and put into service in 2012 (i.e., started generating fee-based cash flows). Management expects to complete another $2.4 billion of project in 2013 and has an additional $4.8 billion of projects under construction that it expects to be completed in 2014 and the first half of 2015. The revenues from these projects will be predominantly fee-based and supported by long-term contracts. EPD recently announced its 34th consecutive quarterly cash distribution increase to $0.66 per unit ($2.64 per annum), a 6.45% increase over the distribution declared with respect to the fourth quarter of 2011. EPD’s current yield is at the low end of the MLPs I follow: As of 3/4/13: Price Quarterly Distribution Yield Magellan Midstream Partners (MMP) $50.07 $0.50000 3.99% Plains All American Pipeline (PAA) $54.59 $0.56250 4.12% Enterprise Products Partners (EPD) $56.82 $0.66000 4.65% Inergy (NRGY) $20.45 $0.29000 5.67% El Paso Pipeline Partners (EPB) $41.30 $0.61000 5.91% Kinder Morgan Energy Partners (KMP) $86.77 $1.29000 5.95% Targa Resources Partners (NGLS) $41.97 $0.68000 6.48% Williams Partners (WPZ) $50.15 $0.82750 6.60% Buckeye Partners (BPL) $56.33 $1.03750 7.37% Energy Transfer Partners (ETP) $47.62 $0.89375 7.51% Regency Energy Partners (RGP) $23.74 $0.46000 7.75% Boardwalk Pipeline Partners (BWP) $26.49 $0.53250 8.04% Suburban Propane Partners (SPH) $42.69 $0.87500 8.20% Table 7 I think EPD’s premium price is justified on a risk-reward basis given EPD’s size, breadth of operations, strong  management team, portfolio of growth projects, structure (no general partner incentive distributions), excess cash from operations, history of minimizing limited partner dilution and performance track record. The price drop to $50.75 cited in a prior article did, in fact, present a buying opportunity. I consider EPD to be a core MLP holding and would continue to accumulate on weakness.
    Wise Analysis
    A Closer Look at El Paso Pipeline Partners' Distributable Cash Flow as of 4Q 2012
  • by , 1 years ago
  • tags: EPB SLNG SNG CIG
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool El Paso Pipeline Partners, L.P. (EPB) owns Wyoming Interstate Company, L.L.C. (“WIC”), Southern LNG Company, L.L.C. (“SLNG”), Elba Express Company, L.L.C. (“Elba Express”), Southern Natural Gas Company, L.L.C. (“SNG”), Colorado Interstate Gas Company, L.L.C. (“CIG”) and Cheyenne Plains Investment Company, L.L.C. (“CPI”), which owns Cheyenne Plains Gas Pipeline Company, L.L.C. (“CPG”). On February 26, 2013, EPB provided its 2012 annual report on Form 10-K. This report contains retrospective adjustments to prior financial statements to reflect changes that occurred after May 24, 2012. On that date EPB and EPB’s parent, El Paso Corporation, were acquired by Kinder Morgan, Inc. (KMI). As part of that transaction, EPB acquired the remaining 14% interest in CIG and all of CPI and CPG. EPB’s financial statements now fully consolidate CPG. Retrospective adjustments were made to prior periods to reflect this CPG consolidation and resulted in increases in net income attributable to EPB of $22 million, $40 million and $40 million for 2012, 2011 and 2010, respectively. As a result of KMI’s acquisition of El Paso, management now assesses segment performance based on earnings before depreciation and amortization (“EBDA”). In addition to depreciation and amortization, this measure excludes interest expense and certain general and administrative expenses such as employee benefits, legal, information technology and other costs that are not deemed controllable by operating management. Revenues, operating income and net income were as follows: Period: 4Q12 4Q11 2012 2011 2010 Revenues 390 388 1,515 1,531 1,454 Operating income 248 211 863 849 819 Net income 178 139 579 512 418 EBDA 316 299 1,202 1,184 1,160 Weighted avg. units o/s (million) 216 206 209 197 122 Operating margin 64% 54% 57% 55% 56% Net margin 46% 36% 38% 33% 29% Table 1: Figures in $ Millions, except weighted average units outstanding and margins “Certain items” increased 2012 EBDA by $27 million as follows: 1) +$34 million of pre-acquisition EBDA related to CPG; 2) -$11 million charge to operating expenses attributable to a canceled software implementation project; 3) +$6 million non-cash adjustment to reduce environmental liabilities for certain CIG environmental projects; and 4) -$2 million amortization of regulatory assets associated with the SNG offshore asset sale. “Certain items” increased 2011 EBDA by $99 million as follows: 1) +$85 million of pre-acquisition EBDA related to CPG; 2) +$17 million of revenue resulting from a customer’s cancellation of its commitment to Phase B of SLNG’s Elba III Expansion; and 3) -$3 million of operating expenses due to the write-off of Elba project development costs. “Certain items” increased 2010 EBDA by $72 million (+$93 million of pre-acquisition EBDA related to CPG and -$21 million non-cash write down based on a FERC order). Net income in 2012 was reduced by $34 million of non-cash severance costs allocated to EPB by El Paso as part of the May 24 transaction. EPB states it has not paid and is not obligated to pay any amount related to this expense. Average throughput volumes (in terms of billion British thermal units per day) on EPB’s pipelines increased 6.8% in 2012 after decreasing 4.3% in 2011 vs. 2010. The generic reasons why distributable cash flow (“DCF”) as reported by master limited partnerships (“MLPs”) may differ from what I call sustainable DCF are reviewed in an article titled “ Estimating sustainable DCF-why and how ”. EPB adopted a new definition of DCF following its acquisition by KMI and its reported DCF numbers are now based on this mew definition. In an article titled Distributable Cash Flow (“DCF”) I present this new definition and provide a comparison to definitions used by other master limited partnerships MLPs. After restating the numbers to conform to this new format, the comparison between reported and sustainable DCF is presented in Table 2 below: Period: 4Q12 4Q11 2012 2011 Net cash provided by operating activities 193 168 716 818 Less: Maintenance capital expenditures (17) (35) (46) (103) Less: Working capital (generated) - - - (7) Less: net income attributable to GP Less: Net income attributable to noncontrolling interests - (6) (10) (93) Sustainable DCF 176 127 660 615 Add: Net income attributable to noncontrolling interests - 6 10 93 Working capital used 36 33 111 - Other (2) (31) (50) (154) DCF (available to LPs and GP) 210 135 731 554 Less: net income attributable to GP (47) (21) (141) (71) DCF as reported (available to LPs) 163 114 590 483 Table 2: Figures in $ Millions Sustainable DCF in 2012 exceeded the 2011 level mainly due to a reduction in distributions to minority interests and due to maintenance capital expenditures being much lower. Management projected maintenance capital expenditures to total $55-60 million in 2012. The actual number was much lower ($46 million) compared to ~$100 million actually spent in 2011 and ~$94 million actually spent in 2010 when EPB was controlled by EL Paso Corporation. Management expects to spend an even lower amount ($40 million) in 2013. Whether the lower levels of maintenance capital expenditure level are sufficient is an open question. The major differences between reported and sustainable DCF are attributable to working capital and various items grouped under “Other”. In deriving reported DCF for 2012 management added back to net cash from operations $111 million of working capital used ($36 million in 4Q12). Under EPB’s definition, reported DCF always excludes working capital changes, whether positive or negative. In contrast, as detailed in my prior articles, in deriving sustainable DCF I generally do not add back working capital used but, on the other hand, I exclude working capital generated. Despite appearing to be inconsistent, this makes sense because in order to meet my definition of sustainability the master limited partnerships should, on the one hand, generate enough capital to cover normal working capital needs. On the other hand, cash generated from working capital is not a sustainable source and I therefore ignore it. Over reasonably lengthy measurement periods, working capital generated tends to be offset by needs to invest in working capital. I therefore do not add working capital consumed to net cash provided by operating activities in deriving sustainable DCF. Items in the “Other” category include numerous adjustments. These adjustments further illustrate the complexity and subjectivity surrounding DCF calculations and highlight the difficulty of comparing MLPs based on their reported DCF numbers. For example, items included in 2012 include non-cash severance costs, pre acquisition costs, and loss on write-off of assets. I exclude these adjustments from my definition of sustainable DCF. Distributions, reported DCF, sustainable DCF and the resultant coverage ratios are shown in below. Note that the coverage ratio I calculate compares total DCF to total distributions to all unitholders (including the general partner). DCF as reported by EPB is DCF available to limited partners (i.e., after distributions made to the general partner). The comparison of reported vs. sustainable coverage shown below therefore includes the reported number had it been calculated pre distribution to the general partner. This adjustment is shown on the third line of Table 3: Period: 4Q12 4Q11 2012 2011 Distributions declared per LP Unit $0.61 $0.49 $2.25 $1.93 Coverage ratio based on reported DCF 0.99 0.97 1.05 1.14 Coverage ratio based on reported DCF pre GP distribution 1.27 1.14 1.30 1.31 Coverage ratio based on sustainable DCF 1.07 1.08 1.17 1.46 Table 3 I find it helpful to look at a simplified cash flow statement by netting certain items (e.g., acquisitions against dispositions) and by separating cash generation from cash consumption. Here is what I see for EPB: Simplified Sources and Uses of Funds Period: 4Q12 4Q11 2012 2011 Capital expenditures ex maintenance & net of proceeds from sale of PP&E 33 (26) (20) (164) Acquisitions, investments (net of sale proceeds) - - (571) (1,412) Cash contributions/distributions related to affiliates & noncontrolling interests - (22) (26) (96) Debt incurred (repaid) (2) (6) - - 31 (54) (617) (1,672) Net cash from operations, less maintenance capex, net income from non-controlling interests, & distributions 11 13 106 295 Debt incurred (repaid) - - 224 453 Partnership units  issued (retired) - - 279 968 Other CF from investing activities, net 4 (3) 2 (3) 15 10 611 1,713 Net change in cash 46 (44) (6) 41 Table 4: Figures in $ Millions Net cash from operations, less maintenance capital expenditures, less cash related to net income attributable to non-partners exceeded distributions by $106 million in 2012 and by $295 million in 2011. EPB is not using cash raised from issuance of debt and equity to fund distributions. Table 5 below compares KMP’s current yield to some of the other MLPs I follow: As of 3/1/13: Price Quarterly Distribution Yield Magellan Midstream Partners (MMP) $50.24 $0.50000 3.98% Plains All American Pipeline (PAA) $54.38 $0.56250 4.14% Enterprise Products Partners (EPD) $56.81 $0.66000 4.65% Inergy (NRGY) $20.06 $0.29000 5.78% El Paso Pipeline Partners (EPB) $41.40 $0.61000 5.89% Kinder Morgan Energy Partners (KMP) $86.72 $1.29000 5.95% Targa Resources Partners (NGLS) $41.29 $0.68000 6.59% Williams Partners (WPZ) $49.82 $0.82750 6.64% Buckeye Partners (BPL) $56.11 $1.03750 7.40% Energy Transfer Partners (ETP) $47.40 $0.89375 7.54% Regency Energy Partners (RGP) $23.67 $0.46000 7.77% Boardwalk Pipeline Partners (BWP) $26.40 $0.53250 8.07% Suburban Propane Partners (SPH) $42.45 $0.87500 8.24% Table 5 4Q12 growth at EPB was driven by completion of expansion projects at SNG, the CIG and CPG drop-downs, by significant increased demand from natural-gas-fired power plants (particularly at SNG where power generation demand was up 30% in 4Q12 and 42% in 2012), and by cost savings achieved after KMI became EPB’s general partner. The cut in maintenance capital expenditures also contributed to the positive change vs. 4Q11. My concerns about these cuts are based on gut feel. But I recognize that it is quite possible that management prudently generated cost savings (including in maintenance expenditures). In 2013, EPB is expected to purchase KMI’s 50% interest in Gulf LNG. There is always a concern regarding these related-party transactions but again I expect management to deal with this prudently and structure an accretive deal for the limited partners. The concern that EPB will be treated as a stepchild by KMI has, in my view, dissipated. While Kinder Morgan Energy Partners LP (KMP) accounts for the bulk of the $11 billion of expansion projects under way at the Kinder Morgan entities, its 2013 projected distribution growth is 6% compared to 13% for EPB. I therefore continue to hold EPB.
    A Closer Look at Kinder Morgan Energy Partners’ Distributable Cash Flow as of 4Q 12
  • by , 1 years ago
  • tags: KMP KMI WPZ MMP PAA
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool On January 16, 2013, Kinder Morgan Energy Partners LP (KMP) reported results of operations for 4Q 2012 and 2012. Segment earnings before DD&A and “certain items” are summarized in Table 1 below: Period: 4Q12 4Q11 2012 2011 Products Pipelines 176 161 703 694 Natural Gas Pipelines 474 290 1,374 951 CO 2 337 281 1,326 1,094 Terminals 198 184 752 701 Kinder Morgan Canada 71 51 229 199 Total 1,256 967 4,384 3,639 Table 1: Figures in $ Millions Products Pipelines’ refined products volumes were down ~1.5% in 2012 compared to 2011, but NGL volumes were up ~22% and ethanol and biofuels volumes were up ~11%. Segment earnings growth in 2012 was only 1.3%, below its 2012 budget of 6%, mainly due contract expiration in the first quarter and to a slower volume ramp-up on the crude and condensate pipeline. The Natural Gas Pipeline segment exceeded the year’s budgeted growth of 19% mainly due to drop downs by KMI into KMP of 100% interest in Tennessee Gas Pipeline and the 50% interest in El Paso Natural Gas pipeline. These interests were contributed for $6.22 billion, including assumed debt, and generated $344 million of incremental earnings between May 25 and December 31, 2012. Growth from the drop-downs was partly offset by lost income due to FTC-mandated asset sales, by lower volumes on KinderHawk as a result of reduced drilling in the dry gas areas, and by worse-than-expected Texas Intrastate performance, primarily as a result of slower than budgeted growth in Eagle Ford volumes. The CO 2 business contributed most in terms of year-to-year organic growth in segment earnings. This segment produces, transports and markets carbon dioxide for use in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. One such field, referred to as the SACROC unit, is comprised of ~56,000 acres in the Permian Basin in Scurry County, Texas. The SACROC unit is one of the largest and oldest oil fields in the United States using carbon dioxide flooding technology. KMP holds a ~97% working interest in this field and has increased production and ultimate oil recovery over the last several years. Management noted it is discovering more and more opportunities to expand the field and to push back the decline curve. The CO 2 segment finished the year modestly below the 26% budgeted growth target mainly due to lower NGL prices (oil volumes and NGL volumes were above budget). Terminals segment earnings growth was driven by the liquids terminals, particularly in Houston and New York Harbor, and by higher demand for export coal. For the full year 2012, coal export volumes were up ~38%. Segment earnings growth in 2012 was 7.3%, slightly below its 2012 budget of 8% growth primarily because of lost business due to the hurricanes, low river water levels that inhibited some volume movements, and lower steel and salt volumes. Kinder Morgan Canada includes the Trans Mountain pipeline system, a 1/3 ownership interest in the Express pipeline system, and the 25-mile Jet Fuel pipeline system. Segment earnings growth in 2012 is primarily attributable to a $17 million decrease in Trans Mountain income tax expenses. Trans Mountain also benefited from higher non-operating income, related primarily to incremental management incentive fees earned from its operation of the Express pipeline system. Earnings from KMP’s equity investment in the Express pipeline system increased year-over-year  mainly due to volumes moving at higher transportation rates on the Express (Canadian) portion of the system, and to higher domestic volumes on the Platte (domestic) portion of the segment. Contributions to net income provided by each segment are summarized in Table 2 below: Period: 4Q12 4Q11 2012 2011 Products Pipelines 145 133 582 585 Natural Gas Pipelines 387 241 1,121 788 CO 2 222 171 885 655 Terminals 146 133 547 506 Kinder Morgan Canada 57 37 173 143 Less: G&A (108) (86) (432) (387) Less: Interest, net (180) (138) (632) (531) Net income before certain items 669 491 2,244 1,759 Less: “certain items” (50) (12) (888) (491) Net income 619 479 1,356 1,268 Table 2: Figures in $ Millions In an article titled Distributable Cash Flow (“DCF”) I present the definition of DCF used by KMP and provide a comparison to definitions used by other master limited partnerships (“MLPs”). KMP’s definition and method of deriving of DCF (what KMP refers to as “DCF before certain items”) is complex and differs considerably from other MLPs I have covered. Using KMP’s definition, DCF per unit for the trailing 12 months (“TTM”) ending 12/31/12 was $5.07, up from $4.68 for the TTM ending 12/31/11. As always, I attempt to assess how the reported DCF figures compare with what I call sustainable DCF for these periods and whether distributions were funded by additional debt or issuing additional units. Given quarterly fluctuations in revenues, working capital needs and other items, it makes sense to review TTM numbers rather than just the quarterly numbers for the purpose of analyzing changes in reported and sustainable distributable cash flows. The generic reasons why DCF as reported by an MLP may differ from sustainable DCF are reviewed in an article titled Estimating Sustainable DCF-Why and How . Applying the method described there to KMP’ results with respect to sustainable cash flowing to the limited partners generates the comparison outlined in Table 3 below: Period: 2012 2011 2010 2009 Net cash provided by operating activities 3,177 2,874 2,420 2,109 Less: Maintenance capital expenditures (285) (212) (179) (172) Less: Working capital (generated) (17) (7) (37) - Less: net income attributable to GP (1,412) (1,180) (1,053) (936) Less: Net income attributable to noncontrolling interests (17) (10) (11) (16) Sustainable DCF 1,446 1,465 1,139 984 Add: Net income attributable to noncontrolling interests 17 10 11 16 Working capital used - - - 203 Risk management activities (53) (73) (157) (144) Other 368 123 367 137 DCF as reported 1,778 1,525 1,360 1,196 Table 3: Figures in $ Millions Table 3 clearly shows the extraordinarily high proportion of cash generated by this partnership that is claimed by Kinder Morgan Inc, (KMI), KMP’s general partner. The principal differences of between sustainable and reported DCF numbers in Table 1 are, in 2011 and 2012, attributable to risk management activities and a host of other items grouped under “Other”. Risk management activities present a complex issue. I do not generally consider cash generated by risk management activities to be sustainable, although I recognize that one could reasonable argue that bona fide hedging of commodity price risks should be included. In this case, the KMP risk management activities items reflect proceeds from termination of interest rate swap agreements rather than commodity hedging and I therefore exclude them. Items in the “Other” category include numerous adjustments as detailed in Table 4 below: Period: 2012 2011 2010 Depreciation (145) (171) (145) Tax deferred 2 (27) (26) Total non-cash compensation adj. (“certain items” netted) 7 8 0 Total impairment and reserve adj. (“certain items” netted) (129) (74) (206) Equity in earnings of unconsolidated investment, net of distributions (43) (25) (3) Interest of non-controlling partners in net income 17 10 11 Other  (no information provided; with “certain items” netted) (77) 156 3 Total “Other” (368) (123) (367) Table 4: Figures in $ Millions These adjustments further illustrate the complexity and subjectivity surrounding DCF calculations and highlight the difficulty of comparing MLPs based on their reported DCF numbers. For example, as indicated by Table 4, depreciation added back for purposes of deriving management’s reported DCF exceeds the amount in the cash flow statement because it includes KMP’s share of depreciation in various joint ventures. I therefore exclude these adjustments from my definition of sustainable DCF. Distributions, reported DCF, sustainable DCF and the resultant coverage ratios are as follows: Period: 4Q12 4Q11 2012 2011 Distributions declared per LP Unit $1.29 $1.16 $4.98 $4.61 DCF per LP unit as reported $1.35 $1.27 $5.07 $4.68 Sustainable DCF per LP unit $0.78 $1.32 $4.12 $4.49 Coverage ratio based on reported DCF 1.04 1.10 1.02 1.01 Coverage ratio based on sustainable DCF 0.60 1.14 0.83 0.97 Table 5 In 2012 management wrote down by $829 million the value of assets to be disposed by KMP as a result of the FTC mandate in connection with the El Paso acquisition. In 2011 asset write-downs totaled $177 million. Management includes these write-downs in its definition of “certain items” and thus does not adjust DCF downwards. I am not comfortable viewing these as one-time adjustments (and therefore simply disregarding them, as does management), especially when they repeat themselves. Hence the significant differences between reported and sustainable DCF. Perhaps I am being too conservative, but I don’t like giving management a “free pass’ on writing down asset values and am not entirely convinced by the “no cash impact” argument. Table 6 below presents a simplified cash flow statement that nets certain items (e.g., acquisitions against dispositions, debt incurred vs. repaid) and separates cash generation from cash consumption in order to get a clear picture of how distributions have been funded: Simplified Sources and Uses of Funds Period: 2012 2011 Capital expenditures ex maintenance & net of proceeds from sale of PP&E 370 (962) Acquisitions, investments (net of sale proceeds) (3,573) (1,305) Other CF from investing activities, net (13.0) - Other CF from financing activities, net (25) (36)   (3,241) (2,303)   Net cash from operations, less maintenance capex, net income from non-controlling interests, & distributions 364 447 Cash contributions/distributions related to affiliates & noncontrolling interests 107 29 Debt incurred (repaid) 1,243 1,090 Partnership units  issued (retired) 1,636 955 Other CF from investing activities, net - 62   3,350 2,583 Net change in cash 109 280 Table 6: Figures in $ Millions Net cash from operations, less maintenance capital expenditures, less cash related to net income attributable to non-partners exceeded distributions by $364 million in the TTM ended 12/31/12 and by $447 million in corresponding prior year period. In light of the low distribution coverage ratios noted in Table 5, how can this excess be explained? I believe the capital structure of the Kinder Morgan partnerships provides an answer. Kinder Morgan Management, LLC (KMR) owns approximately 31% of KMP in the form of i-units that receive distributions in kind. I estimate that had these units received cash instead, the $364 million excess would have been reduced by ~$572 million ($4.98 times an average of ~115 million i-units outstanding) and thus there would have been a shortfall for the TTM ended 12/31/12. Table 7 below compares KMP’s current yield to some of the other MLPs I follow: As of 2/26/13: Price Quarterly Distribution Yield Magellan Midstream Partners (MMP) $49.28 $0.50000 4.06% Plains All American Pipeline (PAA) $54.30 $0.56250 4.14% Enterprise Products Partners (EPD) $55.79 $0.66000 4.73% Inergy (NRGY) $19.77 $0.29000 5.87% El Paso Pipeline Partners (EPB) $41.00 $0.61000 5.95% Kinder Morgan Energy Partners (KMP) $86.09 $1.29000 5.99% Targa Resources Partners (NGLS) $40.97 $0.68000 6.64% Williams Partners (WPZ) $49.37 $0.82750 6.70% Energy Transfer Partners (ETP) $46.98 $0.89375 7.61% Buckeye Partners (BPL) $53.72 $1.03750 7.73% Regency Energy Partners (RGP) $23.52 $0.46000 7.82% Boardwalk Pipeline Partners (BWP) $25.74 $0.53250 8.28% Suburban Propane Partners (SPH) $41.87 $0.87500 8.36% Table 7 KMP has achieved compound annual growth rates in cash distributions to its limited partners of 8.0%, 5.8% and 7.4%, respectively, for the one-year, three-year and five-year periods ended December 31, 2012. Management expects to declare distributions of $5.28 per unit for 2013, up 6% from 2012.  The management team is strong, there are good organic growth opportunities, and KMP has a history of impressive performance for its limited partners. However, despite including earnings from dropped-down assets for periods prior to their acquisition, sustainable DCF for the trailing 12 months ended 12/31/12 did not improve compared to the prior year period and, in fact, declined on a per unit basis. Coverage ratio based on sustainable DCF is below for 2012. Another factor to consider is the high cost of capital resulting from the need to allocate ~50% of available cash flow to KMI. At the 2012 distribution level, KMI received ~ 51% of all quarterly distributions of available cash (~45% attributable to KMI’s general partner and ~6% attributable to KMI’s limited partner interests). Also, KMP has undertaken significant acquisitions to fuel growth, most recently acquiring Copano Energy LLC (CPNO) before having fully digested the drop-downs from KMI’s acquisition of El Paso Corporation. In the 9 months ended September 30, 2012, CPNO generated $4 million of EBITDA and $182 million of Adjusted EBITDA. The ~$5 billion price tag (including debt assumed) is therefore very expensive and could only be made accretive for KMP unitholders by having KMI forgo some of its incentive distribution rights (an amount yet to be determined in 2013, $120 million in 2014, $120 million in 2015, $110 million in 2016 and annual amounts thereafter decreasing by $5 million per year from this level). In addition to issuing ~36 million units to CPNO shareholders, KMP will also need to issue units to pay KMI for  the remaining 50% ownership interest in EPNG (owner of the El Paso and Mojave natural gas pipeline systems); and EPMIC (the joint venture that owns both the Altamont natural gas gathering system, processing plant and fractionation facilities located in the Uinta basin of Utah, and the Camino Real natural gas and oil gathering system located in the Eagle Ford shale formation in South Texas). I therefore remain on the sidelines with respect to KMP. KMI which yields ~4.1% but is expected to grow distributions at ~9% per annum (albeit down from the prior guidance of 12.5% per annum) may be a better alternative.

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