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 , 4/5/13
  • 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 , 3/27/13
  • 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 , 3/25/13
  • 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 , 3/22/13
  • 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 , 3/18/13
  • 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 , 3/12/13
  • 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 , 3/12/13
  • 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 , 3/5/13
  • 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 , 3/4/13
  • 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 , 2/27/13
  • 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.
    A Closer Look at Targa Resources Partners’ Distributable Cash Flow as of 4Q 2012
  • By , 2/19/13
  • tags: NGLS MMP PAA
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool On February 14, 2013, Targa Resources Partners LP (NGLS) reported results of operations for 1Q 2012 and 2012. Certain key operating parameters for 4Q 2012 and for 2012, including 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 Revenues 1,527 1,933 5,884 6,987 Operating income 86 110 343 355 Net income 39 87 203 246 EBITDA 123 160 517 535 Adjusted EBITDA 131 146 515 491 Weighted average units outstanding (million) 94 85 90 84 Gross margin 17.0% 13.4% 17.1% 13.6% Operating margin 5.6% 5.7% 5.8% 5.1% Table 1: Figures in $ Millions, except units outstanding and margins NGLS’ revenues are principally derived from percent-of-proceeds (“POP”) contracts under which it receives a portion of the natural gas and/or natural gas liquids as payment for its gathering and processing services. POP contracts share price risk between the producer and processor. Operating income generally increases as natural gas prices and natural gas liquid prices increase, and decreases as they decrease. 4Q12 revenues decreased by $407 million vs. the prior year period due to hedges and lower realized prices on commodities ($591 million), partially offset by higher commodity sales volumes ($151 million) and higher fee-based and other revenues ($33 million). 2012 revenues decreased by $1,103 million vs. the prior year period due to hedges and lower realized prices on commodities ($1,963 million), partially offset by higher commodity sales volumes ($770 million) and higher fee-based and other revenues ($90 million). Other factors adversely impacting operating income and net income vs. the comparable prior year periods include higher operating expenses (due to acquisition and expansion activities), higher G&A expenses (due to increased compensation), as well as higher interest and depreciations expenses. Management’s 2012 guidance for Adjusted EBITDA was $515-$550 million. NGLS was able to reach the low end of its target despite 25% lower NGL prices than its original assumptions, despite an $8 million impact from Hurricane Isaac and despite $6 million worth of transaction-related expenses for the Bakken Shale Midstream acquisition (Saddle Butte Pipeline, renamed Targa Badlands). In an article titled Distributable Cash Flow (“DCF”) I present the definition of DCF used by NGLS and provide a comparison to definitions used by other master limited partnerships (“MLPs”). Using NGLS’ definition, DCF for 2012 was $354 million ($3.92 per unit) vs. $337 million ($4.00 per unit) in 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 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 NGLS’ results through 9/30/12 generates the comparison outlined in Table 2 below: Period: 4Q12 4Q11 2012 2011 Net cash provided by operating activities 150 210 465 401 Less: Maintenance capital expenditures (20) (25) (68) (82) Less: Working capital (generated) (36) (70) (4) - Less: Net income attributable to noncontrolling interests (5) (11) (29) (41) Sustainable DCF 90 104 365 278 Working capital used - - - 24 Risk management activities 0 3 0 24 Proceeds from sale of assets / disposal of liabilities 0 (1) - (0) Other (3) 1 (11) 11 DCF as reported 86 107 354 337 Table 2: Figures in $ Millions The principal differences between reported and sustainable DCF for 2012 are grouped under “Other”. They relate to non-cash compensation and accretion of retirement obligations which management adds back to derive reported DCF but are not included in my definition of sustainable DCF. The amounts for the period are not material. The principal differences between sustainable and reported DCF numbers for 2011 are attributable to working capital consumed and risk management activities. See a prior article for an explanation of why I exclude these two items from my definition of sustainable DCF. Distributions, reported DCF, sustainable DCF and the resultant coverage ratios are as follows: Period: 4Q12 4Q11 2012 2011 Distribution per unit $0.6800 $0.6025 $2.6075 $2.3125 Distributions made ($ millions) 77 59 286 225 DCF as reported ($ millions) 86 107 354 337 Sustainable DCF ($ millions) 90 104 365 278 Coverage ratio based on reported DCF 1.12 1.81 1.24 1.50 Coverage ratio based on sustainable DCF 1.17 1.75 1.28 1.23 Table 3: Figures in $ Millions, except per unit amounts and coverage ratios Coverage ratio for 2012 was solid. The drop in 4Q12 is unrelated to the Targa Badlands acquisition. Rather it mostly reflects the drop in net cash generated by operating activities and the increase in number of units outstanding. In a prior article I noted that NGLS was acquiring Targa Badlands at an expensive EBITDA multiple and that the effect would be dilutive. Management now expects distribution coverage to be ~ 0.9x in the first half of 2013 and average 1.0x in 2013 due to the dilutive effect of Badlands. However, these lower coverage ratios will also reflect 10%-12% increases in projected distributions for 2013. Badlands is expected to be accretive in 2014 and beyond. I find it helpful to look at 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 in the last two years. Here is what I see for NGLS: Simplified Sources and Uses of Funds Period: 4Q12 4Q11 2012 2011 Capital expenditures ex maintenance, net of proceeds from sale of PP&E (198) (93) (515) (247) Acquisitions, investments (net of sale proceeds) (970) (2) (1,013) (178) Cash contributions/distributions related to affiliates & non-controlling interests (3) (21) (18) (31) Debt incurred (repaid) - (37) - - Other CF from investing activities, net (2) - - - Other CF from financing activities, net (10) - (14) -   (1,183) (152) (1,560) (456)       Net cash from operations, less maintenance capex, less net income from non-controlling interests, less distributions 54 126 112 94 Debt incurred (repaid) 722 - 904 30 Partnership units  issued 386 (0) 555 304 Other CF from investing activities, net - - 2 0 Other CF from financing activities, net - 13 - 7   1,162 139 1,572 435 Net change in cash (21) (13) 12 (21) 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 $54 million in 4Q12 and by $112 million in 2012. Debt and equity issued were used for expansion capital expenditures and acquisitions. NGLS spent $408 million on acquisitions and growth projects in 2011, $540 million in 2012 (excluding the $950 million Targa Badlands acquisition consummated 12/31/12), and estimates it will spend ~$1 billion in 2013. Projects representing aggregate investments in excess of $1.1 billion of organic growth capital will be placed in service in 2013 (mostly in the 2 nd half of the year). Management expects 2013 Adjusted EBITDA to be $600-$650 million and to grow that by 25% in 2014. Table 5 below compares NGLS’ current yield of some of the other MLPs I follow: As of 2/15/13: Price Quarterly Distribution ($) Yield Magellan Midstream Partners (MMP) $49.81 0.5000 4.02% Plains All American Pipeline (PAA) $53.84 0.5625 4.18% Enterprise Products Partners (EPD) $56.48 0.6600 4.67% El Paso Pipeline Partners (EPB) $42.05 0.6100 5.80% Inergy (NRGY) $19.86 0.2900 5.84% Kinder Morgan Energy Partners (KMP) $87.57 1.2900 5.89% Williams Partners (WPZ) $52.83 0.8275 6.27% Targa Resources Partners (NGLS) $41.56 0.6800 6.54% Energy Transfer Partners (ETP) $46.75 0.8938 7.65% Regency Energy Partners (RGP) $23.75 0.4600 7.75% Buckeye Partners (BPL) $53.50 1.0375 7.76% Boardwalk Pipeline Partners (BWP) $26.70 0.5325 7.98% Suburban Propane Partners (SPH) $42.05 0.8750 8.32% Table 5 NGLS’ current yield of 6.54% compares favorably with many of the MLPs I cover. I prefer it so some of the higher yielding partnerships such as Buckeye Partners, Boardwalk Pipeline Partners and Regency Energy Partners. In my reports dealing with those higher yielding partnerships I highlighted my specific concerns with each. Compared to them and to NRGY, I believe NGLS is a better choice and offers a more compelling risk-reward tradeoff.  I am less sure regarding comparison to the others. My concerns center on the expensive acquisition, the low coverage ratio, the high cost of the IDRs, and the still significant exposure to commodity prices. I also believe developing the infrastructure for the Bakken shale is more risky than the Texas shale plays and the Marcellus shale.
    A Closer Look at Inergy L.P.’s Distributable Cash Flow as of 1Q FY2013
  • By , 2/18/13
  • tags: NRGY EPD KMP WPZ
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool On February 5, 2013, Inergy L.P. (NRGY) reported results of operations for the first quarter of fiscal 2013 (1QFY13) ending 12/31/12. Revenues, operating income, net income, earnings before interest, depreciation & amortization and income tax expenses (EBITDA) and other key parameters for 1QFY13 and for the trailing 12 months (“TTM”) ended 12/31/12, as well as for the respective prior year periods, are provided in Table 1: Period : 3M ending 12/31/12 3M ending 12/31/11 TTM ending 12/31/12 TTM ending 12/31/11 Revenues 439 669 1,777 2,226 Gross profit 80 181 510 654 Operating expenses 70 133 413 523 Operating income 10 48 97 131 Net income 3 (4) 572 (53) EBITDA 47 98 797 327 Adjusted EBITDA 57 103 276 345 Weighted average units o/s (million) 132 123 130 119 Table 1: Figures in $ Millions, except weighted average units outstanding Comparisons across periods are difficult because the numbers for the 3-months ending 12/31/11 include the contribution from the retail propane business sold to Suburban Propane Partners (SPH) on August 1, 2012, while the numbers for the 3-months ending 12/31/12 do not; numbers for the TTM ending 12/31/11 include 12 months of contribution from that business while those for the TTM ending 12/31/12 include just 7 months of contribution; and also because of the 24-day stub period contribution relating to a crude oil loading and storage terminal (the COLT Hub) that was acquired on December 7, 2012. EBITDA for the TTM ending 12/31/11 includes a $590 million gain on disposal of the retail propane operations offset by a ~ $48 million loss on the carrying value of the roughly 14.2 million SPH units held by NRGY from August 1 until they were distributed to the NRGY shareholders on September 14. Excluding the retail propane operations from 1QFY12, Adjusted EBITDA of $57.4 million in 1QFY13 reflects a ~20% ($9.7 million) increase over the prior year quarter. Management’s Adjusted EBITDA guidance for fiscal 2013 (ending 9/30/13) is $260 million. Following the sale to SPH, NRGY has two business segments: (1) marketing, supply and logistics operations; and (2) storage and transportation operations. Assets within the first segment include the West Coast fractionation facility, a fleet of 275 tractors and 457 transports, as well as assets held through its stake in Inergy Midstream LP (NRGM): pipelines in New York and Pennsylvania (the North-South Facilities, the 39-mile natural gas interstate MARC I Pipeline, and the 37.5-mile intrastate East Pipeline); and the COLT Hub. The historical results of the retail propane operations that were sold to SPH are also included in this segment. Assets within the second segment include the Tres Palacios natural gas storage facility in Texas as well as assets held through its stake in NRGM: 4 natural gas storage facilities in New York (Stagecoach, Thomas Corners, Steuben and Seneca Lake); 1 natural gas liquids (“NGL”) storage facility in New York (Bath); and a solution-mining and salt production company in New York (US Salt). NRGY’s stake in NRGM is comprised of a ~66% limited partner stake, a non-economic general partner interest and Incentive Distribution Rights (“IDR”) entitling it to receive 50% of NRGM’s distributions above $0.37 per quarter (the current quarterly distribution is $0.39) . NRGM’s results are consolidated within NRGY, so one needs to subtract from the $57.4 million Adjusted EBITDA reported by NRGY the $33 million reported by NRGM separately in 1QFY13 to arrive at ~$24.4 million of Adjusted EBITDA in the quarter for NRGY’s standalone businesses. This compares to approximately $17.2 million in 1QFY12. Management’s Adjusted EBITDA guidance for fiscal 2013 (ending 9/30/13) for NRGY’s standalone businesses is $80 million. Segment revenues and gross margins for 1QFY13 and 1QFY12 are provided in Table 2 below: 3 months ended : 12/31/12 12/31/11 Retail propane (business sold to SPH) 295 Marketing, Supply and Logistics segment 371 314 Storage and Transportation  segment 68 59 Total 439 669 Gross margin: Marketing, Supply and Logistics 8.6% 6.1% Gross margin: Storage and Transportation 70.8% 76.5% Table 2: Figures in $ Millions, except gross margins Until recently, NRGM’s NGL activities were centered on the Marcellus Shale. On December 7, 2012, NRGM completed the $425 million acquisition of Rangeland Energy which owns and operates the COLT Hub in the heart of the Bakken and Three Forks shale oil-producing region. The Colt Hub includes a terminal capable of moving more than 120,000 barrels of crude oil per day by rail, and of storing 720,000 barrels of crude oil. It also has a 21-mile bi-directional crude oil pipeline that connects the terminal to crude oil gathering systems and crude oil interstate pipelines. NRGY’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 the quarter and TTM ended 12/31/12 was $39 million ($0.30 per unit) and $175 million ($1.35 per unit), respectively, compared to $71.6 million ($0.58 per unit) and $226 million ($1.90 per unit) in the comparable prior year periods. Reported DCF numbers may differ considerably from what I consider to be sustainable. The generic reasons for this are reviewed in an article titled Estimating Sustainable DCF-Why and How . Applying the method described there to NRGY results generates the comparison outlined in Table 3 below: Period : 3M ending 12/31/12 3M ending 12/31/11 TTM ending 12/31/12 TTM ending 12/31/11 Net cash provided by operating activities 28 23 244 117 Less: Maintenance capital expenditures (2) (4) (10) (16) Less: Working capital (generated) - - (31) Sustainable DCF 26 19 203 101 Working capital used 32 26 42 Risk management activities (3) (0) 5 (2) Proceeds from sale of assets / disposal of liabilities - 17 - 56 Other (15) 10 (33) 28 DCF as reported 39 72 175 226 Table 3: Figures in $ Millions As previously noted, comparisons across periods are difficult. Sustainable DCF in 1QFY12 includes contribution from the retail propane business sold to SPH while the numbers for the 3-months ending 12/31/12 do not. Sustainable DCF for the TTM ending 12/31/11 includes 12 months of contribution from that business, while the numbers for the TTM ending 12/31/12 include just 7 months of contribution. Also, the numbers for 1QFY13 and the TTM ending 12/31/12 include a stub period contribution relating to the COLT Hub that was acquired on December 7, 2012. I did not see disclosures that enable an apples-to-apples comparison across the periods. The principal differences between sustainable and reported DCF numbers for the two periods presented in Table 3 are attributable to items added back in calculating reported DCF but not included in sustainable DCF. These include cash consumed by working capital, cash generated by a disposition of a liability, and other items (the largest component of which is cash outflows from risk management activities that are not considered as outflows for reported DCF purposes). Under NRGY’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. Coverage ratios are indicated in Table 4 below: Period : 3M ending 12/31/12 3M ending 12/31/11 TTM ending 12/31/12 TTM ending 12/31/11 Distributions ($ Millions) 44 84 243 323 Distributions declared ($ per unit) 0.2900 0.705 1.330 2.829 Weighted average units outstanding (millions) 132 123 130 119 Coverage ratio based on reported DCF 0.89 0.85 0.72 0.70 Coverage ratio based on sustainable DCF 0.59 0.23 0.84 0.31 Table 4 Distributions in Table 4 above include, in addition to amounts paid to NRGY’s partners, payments to non-controlling partners that own a ~34% interest in NRGM.  These amounted to $7.2 million in 1QFY13 and $14.6 million in the TTM ending 12/31/12. Because it is difficult to make comparisons across periods given the noise in the numbers, my focus is on 1QFY13. Granted, it is a shorter period than I typically use to draws conclusions, and granted that this quarter’s numbers are penalized by including only 24 days of the COLT Hub contributions. But still, coverage of the current distribution rate of $1.16 per annum still appears to me to be weak. 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 : 3M ending 12/31/12 3M ending 12/31/11 TTM ending 12/31/12 TTM ending 12/31/11 Net cash from operations, less maintenance capex, net income from non-controlling interests, & distributions (18) (65) (9) (1) Capital expenditures ex maintenance & net of proceeds from sale of PP&E (50) (50) (306) (174) Acquisitions, investments (net of sale proceeds) (423) (20) (436) (85) Debt incurred (repaid) - (145) (29) (189) Other CF from financing activities, net (13) (5) (17) (22) (505) (285) (796) (471) Cash contributions/distributions related to affiliates & noncontrolling interests (including issuance of NRGM units) 225 293 224 293 Debt incurred (repaid) 283 - 556 - Partnership units  issued (retired) (1) (1) (2) 312 Other CF from financing activities, net - - 11 506 292 779 616 Net change in cash 2 7 (17) 145 Table 5: Figures in $ Millions Table 5 indicates that, for the periods covered, distributions have not been funded by cash from operations. Rather, they were funded through issuance of partnership units, issuance of NRGM units and by debt. This is not sustainable. But management has taken steps to address this, including cutting distributions, selling the retail propane business and acquiring the COLT Hub. A single quarter, especially one that does not reflect all these major changes, is not sufficient to draw definitive conclusions as to whether management’s strategy appears to be working. The jury is still out on whether NRGY will be able to generate cash from operations in excess of maintenance capital expenditures sufficient to cover distributions. A comparison of NRGY’s current yield to the other MLPs I follow is presented in Table 6 below: As of 2/15/13: Price Quarterly Distribution ($) Yield Magellan Midstream Partners (MMP) $49.81 0.5000 4.02% Plains All American Pipeline (PAA) $53.84 0.5625 4.18% Enterprise Products Partners (EPD) $56.48 0.6600 4.67% El Paso Pipeline Partners (EPB) $42.05 0.6100 5.80% Inergy (NRGY) $19.86 0.2900 5.84% Kinder Morgan Energy Partners (KMP) $87.57 1.2900 5.89% Williams Partners (WPZ) $52.83 0.8275 6.27% Targa Resources Partners (NGLS) $41.56 0.6800 6.54% Energy Transfer Partners (ETP) $46.75 0.8938 7.65% Regency Energy Partners (RGP) $23.75 0.4600 7.75% Buckeye Partners (BPL) $53.50 1.0375 7.76% Boardwalk Pipeline Partners (BWP) $26.70 0.5325 7.98% Suburban Propane Partners (SPH) $42.05 0.8750 8.32% Table 6 Management’s Adjusted EBITDA guidance for fiscal 2013 (ending 9/30/13) is $260 million on a consolidated basis ($80 million for NRGY’s standalone businesses and $180 for NRGM). This is below the $276 million achieved in the TTM ending 12/31/12. So the combined effect of divesting the propane business, startup of the Marc I pipeline and the acquisition of the COLT Hub in North Dakota will, at least initially, not be dramatic. Other concerns include Anadarko Petroleum Corporation’s claim that it has an option to acquire 25% of the Marc I Pipeline (a lawsuit was initiated in October 2011 against NRGY and is still outstanding), continuous delays in the Finger Lakes project (storage of liquid petroleum gases) in the face of safety and environmental issues, postponement or possible abandonment of the Commonwealth Pipeline project, and no growth at Tres Palacios. On the other hand, year-over-year performance has been strong in NGL marketing, supply & logistics (driven by greater NGL gallons sold and processed) and in the NGL transport business (driven by higher gross profits due to increased volumes and acquisitions). Also, NRGY’s balance sheet has been significantly strengthened following the sale of the retail propane business to SPH. As of 12/31/12 long term debt was $1,024 million, down from $1,704 million in the previous year. As a multiple of Adjusted EBITDA, long term debt was ~3.7x as of 12/31/12 vs. ~5x as of 12/31/11. Note that, in addition to supporting its own debt, NRGY is obligated to provide contingent, residual support of ~$497 million principal amount of SPH’s 7.50% senior unsecured notes. Overall, I believe other MLPs offer more compelling reasons to invest and would not buy NRGY at this price and yield levels.
    Wise Analysis
    A Closer Look at American Capital Agency’s Cash Flows as of 2Q12
  • By , 9/11/12
  • tags: NLY NGLS WPZ BPL AGNC
  • This article was submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool. My prior articles focused on master limited partnerships (“MLPs”), an area I have long followed and invested in. My concern with overly concentrating my portfolio in MLPs has led me to examine mortgage Real Estate Investment Trusts (“mREITs”) as an alternative yield producing vehicle. Indeed, the current dividend yields on some mREITs exceed the distribution yields on many MLPs including El Paso Pipeline Partners (EPB), Enterprise Products Partners (EPD), Energy Transfer Partners (ETP), Kinder Morgan Energy Partners (KMP), Plains All American Pipeline (PAA), and Williams Partners (WPZ). I have been evaluating Annaly Capital Management, Inc. (NLY) and American Capital Agency Corp. (AGNC). This report focuses on AGNC, a Nasdaq-listed mortgage real estate investment trust (“mREIT”) with a market capitalization of ~$12 billion and assets on the balance sheet as of 6/30/12 totaling ~$85 billion. AGNC owns, manages, and finances a portfolio of real estate related investments, including mortgage pass-through certificates, collateralized mortgage obligations, callable debentures and other securities backed by pools of mortgage loans. Total returns generated from the date indicated through 9/9/12 (based on the $35.02 closing price) are summarized in the table below (note that the percent total return is the return for the entire period, not per annum): From Share Price Change thru 7/5/12 Dividends thru 7/5/12 Total Return Approx. Total Return % 12/31/2008 $13.42 $8.74 $22.16 27% 12/31/2009 $8.48 $6.20 $14.68 22% 12/31/2010 $6.28 $3.54 $9.82 22% 12/31/2011 $6.94 $1.10 $8.04 35% Table 1 Past returns appear to be attractive, even more so than those generated by Annaly Capital Management, Inc. (NLY), another large mREIT whose 2Q12 results I reviewed in an article dated August 27, 2012 . The current yield is also enticing at 14.3%. However, investors familiar with my approach know the first question I ask is what portion, if any, of the dividends I am receiving are really “earned”. I am leery of investing in entities (publicly traded partnerships or companies) that pay dividends, or fund distributions, by issuing debt or additional equity. In taking a closer look at AGNC I encountered difficulties similar to those I faced when reviewing the performance of master limited partnerships (“MLPs”). Since money is fungible and the AGNC annual report runs over 100 pages that are frequently hard to understand, ascertaining whether you are genuinely receiving a yield on your money (rather than a return of your money) can be a complicated endeavor. Several examples can illustrate the complexities. The bulk of AGNC’s assets consist of mortgage-backed securities and debentures issued by Fannie Mae, Freddie Mac or Ginnie Mae, and of corporate debt (together, “Agency Securities”). These are classified for accounting purposes as available-for-sale and are reported at fair value with unrealized gains and losses excluded from earnings and reported as a separate component of stockholders’ equity. Another example is discontinuing hedge accounting for its interest rate swaps beginning in 4Q 2012. This will reduce the balance of net losses accumulated on the balance sheet (under “Accumulated Other Comprehensive Income”) with respect to such interest rate swaps and increase the interest expenses over the remaining contractual terms of these swaps. Using the same definition of distributable cash flow (“DCF”) I applied to the analysis of NLY, I create a quantitative standard that I view as an indicator of AGNC’s ability to generate cash flow at a level that can sustain or support an increase in quarterly distribution rates. The definition is relatively simple: net income + amortization (a non-cash item), + losses (or minus gains) on assets & liabilities (also non-cash items), less cash used for working capital. The results for the past 3 years are outlined in Table 2 below: 12 months ending: 12/31/11 12/31/10 12/31/09 Net income 770 288 119 Amortization 361 105 36 Losses (gains) on assets & liabilities (26) (130) (46) Cash used for working capital (89) (30) (16) DCF 1,016 233 93 Dividends paid (664) (173) (80) DCF excess over dividends paid 352 60 13 DCF coverage of dividends 1.53 1.34 1.16 Table 2: Figures in $ Millions except coverage ratios Results for 2Q 2012, 2Q 2011, the first half of 2012 and of 2011 (1H12 and 1H11) are outlined in Table 3 below: Period: 2Q12 2Q11 1H12 1H11 Net income (261) 177 380 311 Amortization 248 79 400 127 Losses (gains) on assets & liabilities 612 6 349 (10) Cash used for working capital - (27) (43) (65) DCF 599 235 1,086 363 Dividends paid (286) (135) (600) (226) DCF excess over dividends paid 313 100 486 137 DCF coverage of dividends 2.09 1.74 1.81 1.61 Table 3: Figures in $ Millions except coverage ratios Amortization charges reflect the purchase of Agency Securities at a premium (so valued because their stated coupon exceeds market rates). The premium is paid with the expectation that the higher than market coupon will be paid over the expected life of the security. If the expectation turns out to be wrong and the actual life is shortened due to more rapid than anticipated repayment of principal, DCF will suffer. Amortization for an mREIT is therefore a far less predictable and stable component of DCF than an MLP’s depreciation charge. Losses (gains) on assets and liabilities in Tables 2 and 3 are comprised of realized and unrealized gains and losses on mortgage backed securities, debentures, equity securities, interest rate swaps. The losses and gains are added and subtracted, respectively, because they are non-cash items. As part of my analysis, I also created a simplified cash flow statement designed to shed light on the sustainability of the dividends by, for example, grouping together and netting out numerous line items that deal with gains and losses that are reported in the income statement but are non-cash items (and therefore reversed out in the cash flow statement). I also separate cash generation from cash consumption and group together and net out numerous line items that deal with cash outflows for assets (e.g., acquiring assets outright or receiving assets as collateral and lending against them) and cash generated by assets (e.g., selling assets outright or giving assets as collateral and borrowing against them). This reduces AGNC’s cash flow statement to just a few lines. Results for the past 4 years are outlined in Table 4 below: Simplified Cash Flow Statement: 12 months ending: 12/31/11 12/31/10 12/31/09 DCF excess over dividends paid 352 60 13 Non-repo debt issued (repaid) (19) 73 - Shares issued 4,377 1,055 222 Other cash generated, net 0 0 0 4,710 1,187 235     Payments for assets, net (3,257) (1,160) (87) Increase (decrease) in restricted cash (260) (56) (1) (3,517) (1,217) (88)     Net increase in cash & cash equivalents 1,194 (30) 147 Table 4: Figures in $ Millions In these simplified cash flow statements proceeds from, and payments for, assets contain numerous types of netted items, including: a) repos and reverse repos; b) securities borrowed and loaned; c) securities purchased and sold; d) principal payments on, or maturities of, securities owned; e) equity investments (including investments in affiliates). Of course, the net increase (decrease) in cash and cash equivalents ties to the company’s financial statements. Results for 2Q 2012, 2Q 2011, 1H12 and 1H11 are outlined in Table 5: Period: 2Q12 2Q11 1H12 1H11 DCF excess over dividends paid 313 100 486 137 Cash generated by working capital 15 - - - Non-repo debt issued (repaid) 896 (6) 892 (11) Preferred shares issued 167 - 167 - Common shares issued 155 1,368 2,360 3,121 1,546 1,462 3,905 3,247       Payments for assets, net (1,222) (1,024) (3,207) (2,682) Increase (decrease) in restricted cash 13 (114) 34 (113) (1,209) (1,138) (3,173) (2,795)       Net increase in cash & cash equivalents per financial statements 337 325 732 453 Table 5: Figures in $ Millions Roughly speaking, on a net basis over the 3-year period of 2009-2011, AGNC generated ~$1.3 billion, raised a further $5.7 billion by issuing equity and non-repo debt (of which only $~54 million was from such debt) and used the total of ~$7.0 billion to increase its portfolio ($4.5 billion), to pay dividends ($0.9 billion) and to increase its cash and restricted cash balances ($1.6 billion). Over this period, AGNC has demonstrated an ability to generate cash sufficient to both fund dividends and supplement funds raised via issuance of equity and debt in order to increase the size of the investment portfolio. For the 6-month period ending 6/30/12, AGNC generated ~$1.1 billion and raised ~ $3.4 billion via issuance of common shares, preferred shares, and debt. It used the total of $4.5 billion to increase its portfolio (~$3.2 billion), to pay dividends (~$0.6 billion), and to increase its cash balance ($0.7 billion). Clearly a 14.3% yield does not come without risks and past performance may not be a good indicator of future performance. All mREITs, including AGNC, have benefited from the accommodative stance of the Federal Reserve Bank which, for the past several years, has resulted in a relatively steep yield curve, albeit at low absolute rates. The shape of yield curve and amount of leverage (the bulk of which is generated via the repurchase markets) are the key drivers of return for AGNC which relies primarily on short-term borrowings to acquire Agency Securities with long-term maturities. Accordingly, profitability may be adversely affected if short-term interest rates increase. They could, as noted, also be adversely affected if mortgage rates decrease since this is likely to result in more rapid prepayments. In fact, in its 2011 annual report AGNC estimated that a 1% increase in rates is likely to cause far less damage (3.1% drop in projected net interest income) than a 1% decrease in interest rates (13.2% drop in projected net interest income). AGNC’s Form 10-K lists numerous other risks. I look at several risk and performance parameters, including: Leverage : In reviewing the table below, note that it is based on my more simplistic calculations of leverage (management calculates leverage at period end by dividing the sum of the amount outstanding under repurchase agreements, net receivable / payable for unsettled agency securities and other debt by total stockholders’ equity at period end). In 2Q12 management decreased leverage, in part through asset sales, and also repositioned the portfolio into lower coupon agency Mortgage Backed Securities (“MBS”) and lower loan balance and Home Affordable Refinance Program (“HARP”) securities, which are less susceptible to prepayment risk, reducing the impact of the decline in long-term interest rates on the portfolio. Reduced leverage reduces both interest rate risk and systemic risk (e.g., crisis in Europe, regulatory pressures for mortgage finance reform, future of Freddie Mac & Fannie Mae, SEC review of the exemption granted to mortgage REITs from the 1940 Act which would cause them to be considered as mutual funds). However, in 2012 leverage has increased: Period: 2Q12 1Q12 4Q11 3Q11 2Q11 1Q11 total assets  / total equity 7.96 8.57 7.99 8.21 7.73 7.64 total debt / total equity 8.10 8.57 7.99 8.21 7.73 7.64 Sensitivity to changes in interest rates : data provided by management is outlined in Table 6 below. It indicates a limited exposure to changes in interest rates as of 6/30/12: Change in Interest Rate (1) Projected % Change in Net Interest Income (2) Projected % Change in Portfolio Value Projected % Change in Net Asset Value -100 Basis Points -23.60% -1.18% -10.58% -50 Basis Points -7.00% -0.45% -4.05% Base Interest Rate     +50 Basis Points -5.40% 0.02% 0.18% +100 Basis Points -9.60% -0.39% -3.47% Assuming movement is in the entire yield curve Including interest expense on interest rate swaps, but excluding costs of supplemental hedges Table 6 However, this may not be a reliable indication of exposure to changes in interest rates for two major reasons: first, the assumption that the entire yield curve moves in tandem is not as bad a scenario for AGNC as a further flattening (to say nothing of inversion) of the curve. Second, management’s estimates speed of prepayment vary at each interest rate level and we have no way of knowing how conservative or aggressive these assumptions are. Prepayment speeds as reflected by the Constant Prepayment Rate (“CPR”): In the aggregate, mortgage backed securities purchased by AGNC at a premium exceed those it purchased at a discount. Therefore, the faster the prepayment rate the greater the loss. AGNC’s 2011 Annual Report presents the following illustration of how significant is the impact of CPR rates on Return on Equity (ROE): CPR rate 10% 20% 30% 40% Asset Yield 3.43% 2.73% 1.93% 1.03% Cost of Funds -0.75% -0.75% -0.75% -0.75% Net Margin 2.68% 1.98% 1.18% 0.28% ROE at 8x Leverage 24.90% 18.60% 11.40% 3.20% Table 7 In addition to the adverse effect on ROE, the portfolio itself could sustain losses as a result of faster prepayments. The 2Q12 report indicates AGNC holds its portfolio of Agency MBS at a ~4.7% premium to the face value of the mortgages and that there has been a further mark-to-market (“MTM”) appreciation of ~2.2% for a total of ~7% excess over the adjusted (i.e., unamortized) purchase price. As I see it, if prepayments accelerate, the 4.7% premium will contract and the MTM gains will also decline. Hedges, depending on how effective and extensive they are, can help offset the potential loss which, on a $76 billion portfolio, could be very significant. A rear-view mirror of CPR rates indicates they have been holding steady for the past year: Period: 2Q12 1Q12 4Q11 3Q11 2Q11 1Q11 CPR rate 10% 10% 9% 8% 9% 13% Duration: Duration is the length of time required to recoup losses caused by a percent increase in short and long-term interest rates (losses are recouped by reinvesting at higher interest rates). Unfortunately, AGNC does not provide duration data. Net interest spread: data provided by management indicates net interest spread has been declining since 6/30/11: Period: 2Q12 1Q12 4Q11 3Q11 2Q11 1Q11 Net spread 1.65% 2.31% NA 2.14% 2.46% 2.58% Management noted in its 2Q12 report that it had repositioned the portfolio into lower coupon agency MBS to further protect our portfolio against prepayment risk. The weighted average agency MBS coupon was 3.86% as of June 30, 2012 compared to 4.23% as of December 31, 2011. Book value per share: Period: 2Q12 1Q12 4Q11 3Q11 2Q11 1Q11 Book value 26.26 29.06 27.71 26.90 26.76 25.96 In summary, the bulk of investor returns have come from share price appreciation rather than dividends. Looking ahead, I don’t expect this to continue and believe investors should not factor in future share price appreciation. change. If management’s measurement of net interest margin is correct, the current yield on average interest earning assets (2.73%), net interest margin (1.65%) and leverage (~8) indicate a return on equity (and hence sustainable distributions) of about 14.3%, which equals the current yield. This very rough, back-of-the-envelope, calculation indicates that distributions are sustainable under current conditions. My assessment is that there is less risk in NLY than in AGNC because its leverage is lower, it appears to be less adversely affected by changes in interest rates, and it trades closer to book value (possibly offering more protection against share price declines). On the other hand, AGNC has demonstrated, and appears to continue to offer, better returns. I cannot make a precise risk-reward calculation and would be comfortable investing in either (bearing in mind their returns will be highly correlated). As always, there is a risk that current conditions will change and investors should perform their own due diligence and assess their individual tolerance for risk before buying or selling the shares.
    Wise Analysis
    A Closer Look at Annaly Capital Management’s Cash Flows as of 2Q12
  • By , 8/28/12
  • tags: NLY NGLS WPZ BPL AGNC
  • This article was submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool. My prior articles focused on master limited partnerships (“MLPs”), an area I have long followed and invested in. My concern with overly concentrating my portfolio in MLPs has led me to examine mortgage Real Estate Investment Trusts (“mREITs”) as an alternative yield producing vehicle. Indeed, the current dividend yields on some mREITs exceed the distribution yields on many MLPs including El Paso Pipeline Partners (EPB), Enterprise Products Partners (EPD), Energy Transfer Partners (ETP), Kinder Morgan Energy Partners (KMP), Plains All American Pipeline (PAA), and Williams Partners (WPZ). I have been evaluating Annaly Capital Management, Inc. (NLY) and American Capital Agency Corp. (AGNC). This report focuses on NLY, the largest mREIT listed on the NYSE with a market cap of ~$16.7 billion and assets on the balance sheet as of 6/30/12 totaling ~$128 billion. NYL owns, manages, and finances a portfolio of real estate related investments, including mortgage pass-through certificates, collateralized mortgage obligations (“CMOs”), callable debentures and other securities backed by pools of mortgage loans. Total returns generated through 8/24/12 (based on the $17.16 closing price) are summarized in Table 1 below: From Share Price Change thru 8/24/12 Dividends thru 8/24/12 Total Return Approx. Total Return % 12/31/2008 $1.45 $13.13 $14.58 13% 12/31/2009 ($0.19) $6.20 $6.01 10% 12/31/2010 ($0.76) $3.54 $2.78 7% 12/31/2011 $1.20 $1.10 $2.30 15% Table 1 Past returns appear to be attractive and the current yield is enticing at 12.8%. However, investors familiar with my approach know the first question I ask is what portion, if any, of the dividends I am receiving are really “earned”. I am leery of investing in entities (publicly traded partnerships or companies) that pay dividends, or fund distributions, by issuing debt or additional equity. In taking a closer look at NLY I encountered difficulties similar to those I faced when reviewing the performance of MLPs. Since money is fungible and the NLY annual report runs over 100 pages that are frequently hard to understand, ascertaining whether you are genuinely receiving a yield on your money (rather than a return of your money) can be a complicated endeavor. Several examples can illustrate the complexities. The bulk of NLY’s assets consist of mortgage-backed securities and debentures issued by Fannie Mae, Freddie Mac or Ginnie Mae, and of corporate debt (together, “Investment Securities”). These are classified for accounting purposes as available-for-sale and are reported at fair value with unrealized gains and losses excluded from earnings and reported as a separate component of stockholders’ equity. The effect can be dramatic, as seen in 3Q 2011 when reported losses (realized and unrealized) amounted to 38.8% of the average equity and NLY‘s net loss for the period amounted to ~$926 million. But there were $1.1 billion of unrealized gains in that quarter that showed up only on the balance sheet, not the income statement. Another example is the subjectivity involved in determining net interest margin, an important performance indicator. Beginning June 30, 2011, NLY reclassified “interest expense on swaps” to “realized gains (losses) on swaps” thus changing the way net interest margin is calculated, Therefore, I find NLY’s net interest margins, reported earnings, earnings per share and earnings multiples to be of limited value as indicators of performance or of ability to generate sustainable dividends. The treatment of borrowing and lending via repurchase and reverse repurchase agreements (“repos”) is yet another example. NLY reports cash flow from these activities as cash flows from operating activities when they are performed by RCap (NLY’s wholly owned broker-dealer subsidiary), but when they are not performed by RCap, they appear as cash flow from investing activities. Therefore I find NLY’s distinctions between the various categories on the cash flow statement (i.e., operations, investments and financing) to be of limited value in understanding NLY’s ability to generate sustainable dividends. In light of these issues, I developed my own definition of distributable cash flow (“DCF”), thus creating a quantitative standard that I view as an indicator of NLY’s ability to generate cash flow at a level that can sustain or support an increase in quarterly distribution rates. The definition is relatively simple: net income + amortization (a non-cash item), + losses (or minus gains) on assets & liabilities (also non-cash items), less cash used for working capital. The results for the past 4 years are outlined in Table 2 below: 12 months ending: 12/31/11 12/31/10 12/31/09 12/31/08 Net income 344 1,267 1,961 346 Amortization 808 669 256 104 Losses (gains) on assets & liabilities 1,707 139 (448) 780 Cash used for working capital (49) (2) (146) (123) DCF 2,810 2,074 1,623 1,107 Dividends paid (2,041) (1,599) (1,269) (975) DCF excess over dividends paid 769 475 354 132 DCF coverage of dividends 1.38 1.30 1.28 1.14 Table 2: Figures in $ Millions except coverage ratios Results for 2Q 2012, 2Q 2011, the first half of 2012 and of 2011 (1H12 and 1H11) are outlined in Table 3 below: Period: 2Q12 2Q11 1H12 1H11 Net income (91) 121 811 821 Amortization 311 128 601 304 Losses (gains) on assets & liabilities 541 462 86 261 Cash used for working capital - - - - DCF 762 710 1,497 1,386 Dividends paid (541) (503) (1,098) (911) DCF excess over dividends paid 221 207 400 474 DCF coverage of dividends 1.41 1.41 1.36 1.52 Table 3: Figures in $ Millions except coverage ratios Losses (gains) on assets and liabilities in Tables 2 and 3 are comprised of realized and unrealized gains and losses on mortgage backed securities, debentures, equity securities, interest rate swaps. The losses and gains are added and subtracted, respectively, because they are non-cash items. As part of my analysis, I also created a simplified cash flow statement designed to shed light on the sustainability of the dividends by, for example, grouping together and netting out numerous line items that deal with gains and losses that are reported in the income statement but are non-cash items (and therefore reversed out in the cash flow statement). I also separate cash generation from cash consumption and group together and net out numerous line items that deal with cash outflows for assets (e.g., acquiring assets outright or receiving assets as collateral and lending against them) and cash generated by assets (e.g., selling assets outright or giving assets as collateral and borrowing against them). This reduces the over 50 line items in NLY’s cash flow statement to just a few. Results for the past 4 years are outlined in Table 4 below: Simplified Cash Flow Statement: 12 months ending: 12/31/11 12/31/10 12/31/09 12/31/08 DCF excess over dividends paid 769 475 354 132 Proceeds from assets, net - - 90 - Convertible Senior Notes issued - 582 - - Shares issued 5,816 1,331 147 2,244 Other cash generated, net 5 - 5 73 6,590 2,387 595 2,449     Payments for assets, net (5,879) (3,600) - (1,643) Other cash used, net - (9) - - (5,879) (3,609) – (1,643)     Net increase in cash & cash equiv. 712 (1,222) 595 805 Table 4: Figures in $ Millions In these simplified cash flow statements proceeds from, and payments for, assets contain numerous types of netted items, including: a) repos and reverse repos; b) securities borrowed and loaned; c) securities purchased and sold; d) principal payments on, or maturities of, securities owned; e) equity investments (including investments in affiliates). Of course, the net increase (decrease) in cash and cash equivalents ties to the company’s financial statements. Results for 2Q 2012, 2Q 2011, 1H12 and 1H11 are outlined in Table 5: Period: 2Q12 2Q11 1H12 1H11 DCF excess over dividends paid 221 207 400 474 Cash generated by working capital 88 79 112 34       Convertible Senior Notes issued (repaid) 728 - 728 - Preferred shares issued 291 - 291 - Common shares issued 4 458 6 3,403 Other cash generated, net 1 1 - 2 1,332 746 1,536 3,913       Payments for assets, net (1,341) (701) (1,595) (3,794) Other cash used, net - - (11) - (1,341) (701) (1,606) (3,794)       Net increase in cash & cash equivalents per financial statements (8) 45 (70) 119 Table 5: Figures in $ Millions Roughly speaking, on a net basis over the 4-year period of 2008-2011, NLY generated ~$8 billion, raised a further $10.1 billion via equity and debt (of which only $0.6 billion from debt via issuance of senior convertible notes) and used the total of $18.1 billion to increase its portfolio ($12.2 billion) and to pay dividends ($5.9 billion). For the 6-month period ending 6/30/12, NLY generated ~$1.5 billion, raised ~ $1 billion via issuance of senior notes and preferred shares, and generated ~$182 million by reducing working capital (including cash balances). It used the total of $2.7 billion to increase its portfolio (~$1.6 billion) and to pay dividends (~$1.1 billion). NLY continues to demonstrate an ability to generate cash sufficient to both fund dividends and supplement funds raised via issuance of equity and debt in order to increase the size of the investment portfolio. Clearly the 12.8% yield does not come without risks and past performance may not be a good indicator of future performance. NLY has benefited from the accommodative stance of the Federal Reserve Bank which, for the past several years, has resulted in a relatively steep yield curve, albeit at low absolute rates. The shape of yield curve and amount of leverage (the bulk of which is generated via the repurchase markets) are the key drivers of return for NLY which relies primarily on short-term borrowings to acquire Investment Securities with long-term maturities. Accordingly, profitability may be adversely affected if short-term interest rates increase or if the spread narrows. NLY’s Form 10-K lists numerous other risks, including the health of its Chairman, CEO and President. I look at several risk and performance parameters: Leverage : Management has been keeping leverage at the low end of its 8 to 12 leverage band since 2007. Reduced leverage reduces both interest rate risk and systemic risk (e.g., crisis in Europe, regulatory pressures for mortgage finance reform, future of Freddie Mac & Fannie Mae, SEC review of the exemption granted to mortgage REITs from the 1940 Act which would cause them to be considered as mutual funds). However, in 2012 leverage has increased: Period: 2Q12 1Q12 4Q11 3Q11 2Q11 1Q11 total assets  / total equity 6.83 6.50 5.91 6.09 6.16 6.60 total debt / total equity 7.03 6.57 5.98 6.16 6.24 6.69 Sensitivity to changes in interest rates : data provided by management is outlined in Table 6 below. It indicates a limited exposure to changes in interest rates as of 6/30/12: Change in Interest Rate (1) Projected % Change in Economic Net Interest Income (2) Projected % Change in Portfolio Value, with Effect of Interest Rate Swaps -75 Basis Points 4.54% 0.22% -50 Basis Points 2.80% 0.04% -25 Basis Points 1.12% 0.02% Base Interest Rate - - +25 Basis Points -1.13% -0.09% +50 Basis Points -2.78% -0.27% +75 Basis Points -3.91% -0.57% Assuming movement is in the entire yield curve Including interest expense on interest rate swaps Table 6 However, this may not be a reliable indication of exposure to changes in interest rates for two major reasons: first, the assumption that the entire yield curve moves in tandem is not as bad a scenario for NLY as a further flattening (to say nothing of inversion) of the curve. Second, management’s estimates speed of prepayment vary at each interest rate level and we have no way of knowing how conservative or aggressive these assumptions are. Prepayment speeds as reflected by the Constant Prepayment Rate (“CPR”): In the aggregate, mortgage backed securities purchased by NLY at a premium exceed those it purchased at a discount. Therefore, the faster the prepayment rate the greater the loss. While CPR rates have increased significantly vs. 6/30/11, they appear to be leveling off: Period: 2Q12 1Q12 4Q11 3Q11 2Q11 1Q11 CPR rate 19% 19% 22% 18% 11% 17%   Duration: as of 12/31/11 duration was at a short 1.2 years. Duration is the length of time required to recoup losses caused by a percent increase in short and long-term interest rates (losses are recouped by reinvesting at higher interest rates). Giving effect to swap transactions, NLY reported average duration (0.4) years as of 12/31/11. The negative number indicates that, giving effect to swap transactions, the duration of NLY’s assets is shorter than that of its liabilities. An update as of 6/30/12 was not provided. Net interest spread: data provided by management indicates net interest spread has been declining since 6/30/11: Period: 2Q12 1Q12 4Q11 3Q11 2Q11 1Q11 Net spread 1.54% 1.71% 1.71% 2.07% 2.45% 2.16% Management seeks to mitigate the effect of changes in interest rates by matching adjustable rate assets with variable rate borrowings and therefore swaps its fixed rate liabilities via agreements whereby it receives fixed rate payments and makes floating rate payments. Management noted in the its 2Q12 report that the weighted average rate it pays rate on these interest swaps  will continue to decline “…for the immediately foreseeable periods…” as a result of interest rate swaps with higher pay rates maturing or being terminated and the replacement of such swaps with interest rate swaps with lower pay rates. Book value per share: Period: 2Q12 1Q12 4Q11 3Q11 2Q11 1Q11 Book value 16.23 16.18 16.06 16.22 14.19 15.59 In summary, the bulk of investor returns have come from dividends rather than capital appreciation. Looking ahead, I don’t expect this to change. In fact, if management’s measurement of net interest margin is correct, the current yield on average interest earning assets (3.04%), net interest margin (1.54%) and leverage (~7) indicate a return on equity (and hence sustainable distributions) of about 12.3%, which is slightly below the 12.8% current yield. This very rough, back-of-the-envelope, calculation indicates that for distributions to be sustainable under current conditions, and assuming no reduction in the investment portfolio, they would have to be reduced from the current rate of $0.55 per quarter to ~$0.53 per quarter. Should this modest reduction occur and be accompanied by a sharp decline in share price, a buying opportunity may develop. As always, investors should perform their own due diligence and assess their individual tolerance for risk before buying or selling the shares.
    Wise Analysis
    A Closer Look at Regency Energy Partners' Distributable Cash Flow as of 2Q 2012
  • By , 8/27/12
  • tags: RGP NGLS WPZ BPL KMI
  • This article was submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool. On August 7, 2012, Regency Energy Partners LP (RGP) reported results of operations for 2Q 2012. Revenues, operating income, net income and earnings before interest, depreciation & amortization and income tax expenses (EBITDA) were as follows: Period: 2Q12 2Q11 1H12 1H11 Revenues 312 356 670 674 Operating income 23 5 33 13 Net income 29 15 58 29 EBITDA 102 80 212 155 Adjusted EBITDA 115 103 249 195 Weighted average units outstanding (million) 170 143 164 140 Table 1: Figures in $ Millions except shares outstanding RGP has 5 business segments: (1) Gathering and Processing provides “wellhead-to-market” services to producers of natural gas. This segment also includes RGP’s investment in Ranch JV, which processes natural gas delivered from shale formations in west Texas; (2) Contract Compression owns and operate a fleet of compressors used to provide turn-key natural gas compression services; (3) Contract Treating owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management, to natural gas producers and midstream pipeline companies; (4) the Corporate and Others segment comprises a small regulated pipeline and our corporate offices; and (5) the Joint Ventures segment. Segment margin performance of the first 4 segments in 2Q12 vs. 2Q11 and in 1H12 (first half of 2012) vs. 1H11 is summarized below: Period: 2Q12 2Q11 1H12 1H11 Gathering and Processing 79 50 151 104 Contract Compression 38 37 77 78 Contract Treating 7 8 15 15 Corporate and Others 5 5 10 10 Eliminations (5) (3) (10) (9) Total segment margin: 125 97 243 198 Table 2: Figures in $ Millions As indicated by Table 2, the improvement in total segment margin has been driven by Gathering and Processing which benefitted from increased volumes in south and west Texas and north Louisiana. RGP does not record segment margin for the fifth segment, Joint Ventures, because it records its ownership percentages of the net income of its unconsolidated affiliates as income from unconsolidated affiliates in accordance with the equity method of accounting. The Joint Ventures segment includes: (1) a 49.99% general partner interest in RIGS Haynesville Partnership Co.,(“HPC”), which owns a 450 mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets; (2) a 50% membership interest in Midcontinent Express Pipeline LLC (“MEP”), which owns an interstate natural gas pipeline with approximately 500 miles stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama; and (3) a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including NGL pipelines, storage, fractionation and processing facilities located in the states of Texas, Mississippi and Louisiana. Income from these unconsolidated affiliates in 2Q12 vs. 2Q11 and in 1H12 vs. 1H11 is summarized below: Period: 2Q12 2Q11 1H12 1H11 HPC 11.6 13.7 21.5 27.3 MEP 10.2 10.1 20.9 20.3 Lone Star 12.4 8.4 23.7 8.3 Table 3: Figures in $ Millions As indicated by Table 3, the primary driver of performance for the Joint Ventures segment is Lone Star which became operational in May 2011 and provided a full quarter’s contribution in 2Q12. Given quarterly fluctuations in revenues, working capital needs and other items, it makes sense to review trailing 12 months (“TTM”) numbers rather than quarterly numbers for the purpose of analyzing changes in reported and sustainable distributable cash flows. RGP’s definition of Distributable Cash Flow (“DCF”) and a comparison to definitions used by other master limited partnerships (“MLPs”) are described in an article titled Distributable Cash Flow (“DCF”) . Using that definition, DCF for the trailing 12 months (“TTM”) period ending 6/30/12 was $330 million ($2.09 per unit), up from $256 million ($1.89 per unit) in the comparable prior year period. 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 RGP’s results through 1Q 2012 generates the comparison outlined in the table below: 12 months ending: 6/30/12 6/30/11 Net cash provided by operating activities 235 217 Less: Maintenance capital expenditures (29) (12) Less: Working capital (generated) - (11) Less: Net income attributable to noncontrolling interests (2) (1) Sustainable DCF 204 193 Add: Net income attributable to noncontrolling interests 2 1 Working capital used 24 - Risk management activities 2 0 Proceeds from sale of assets / disposal of liabilities 21 20 Other 76 42 DCF as reported 330 256 Table 4: Figures in $ Millions The principal differences between reported DCF and sustainable DCF relate to working capital, proceeds from asset sales, and RGP’s substantial, but non-controlling, stakes in the entities within its Joint Ventures segment. Under RGP’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 (this accounts for $24 million of the variance between reported and sustainable DCF in 2Q12). 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. Similarly, I also do not add back into DCF items I do not regard as sustainable, such as proceeds from asset sales. The largest variance between reported and sustainable DCF related to RGP’s substantial, but non-controlling, stakes in the entities within its Joint Ventures segment. Pursuant to Generally Accepted Accounting Principles (GAAP), the Partnership records its share of the net income in these other pipelines as income from unconsolidated affiliates in accordance with the equity method of accounting. However, for purposes of calculating DCF, RGP treats these as if they were fully consolidated by deducting its share of net income, adding its share of the earnings before interest, taxes, depreciation & amortization (EBITDA), and further adjusting to take into account its share of interest expense and maintenance capital expenditures. On the one hand, I can accept classifying RGP’s share of cash flows generated from these entities in the sustainable category despite the fact that RGP does not control them (i.e., cannot determine what to do with the cash they generate). This is because they are similar in every other respect to RGP’s other pipeline assets and because RGP and/or Energy Transfer Equity, L.P. (ETE), RGP’s general partner, do exercise a significant degree of influence over them. On the other hand, RGP’s share of cash flows generated from these entities (which accounts for the bulk of the $76 million and the $42 million in the “Other” line item) does not, as of the date of the report, appear on RGP’s balance sheet and does not increase RGP’s end-of-period cash balance. Coverage ratios, with and without this line item, are as indicated in the table below: 12 months ending: 6/30/12 6/30/11 Distributions to unitholders ($ Millions) $302 $250 Weighted average units outstanding 158 136 Coverage ratio based on reported DCF 1.09 1.03 Coverage ratio based on sustainable DCF (including non-consolidated entities) 0.93 0.94 Coverage ratio based on sustainable DCF 0.68 0.77 Table 5 Whichever way you look at it, these are thin 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 RGP: Simplified Sources and Uses of Funds 12 months ending: 6/30/12 6/30/11 Net cash from operations, less maintenance capex, less net income from non-controlling interests, less distributions (96) (45) Capital expenditures ex maintenance, net of proceeds from sale of PP&E (362) (218) Acquisitions, investments (net of sale proceeds) (594) (200) Cash contributions/distributions related to affiliates & noncontrolling interests - (552) Other CF from financing activities, net - (28) (1,052) (1,042) - - Cash contributions/distributions related to affiliates & noncontrolling interests 438 - Debt incurred (repaid) 98 417 Partnership units  issued 529 624 Other CF from financing activities, net 1 - 1,065 1,041 Net change in cash 13 (1) Table 6: Figures in $ Millions Net cash from operations, less maintenance capital expenditures, less net income from non-controlling interests did not cover distributions in both periods. The shortfall was $96 million for the TTM ending 6/30/12 and $45 million for the comparable prior year period. Table 6 therefore shows that distributions in both TTM periods were partially financed by issuing equity and debt, despite the fact that RGP’s reported DCF exceeded the amount distributed (as shown in Tables 4 and 5). The reason, as previously noted, is that reported DCF included items that never make it into the cash flow statement (i.e., cash flows from the non-consolidated pipelines and some other adjustments). Growth capital expenditures in 2012, including capital contributions to RGP’s unconsolidated affiliates (i.e., the non-controlling, stakes in other pipelines), are expected to total ~$800 million, of which ~ $373 million was expended in 1H 2012. With long term debt at ~4.4x EBITDA for the TTM ending 6/30/12 and over $400 million of growth capital expenditures required in 2H 2012, I would not be surprised to see additional equity issuances in 2012. The projects being financed will begin to impact RGP’s results only in 2013-2014. Energy Transfer Equity, L.P. (ETE), RGP’s general partner, is entitled, via its incentive distribution rights (“IDRs”), to 48% of any increase in RGP’s current distributions. RGP is at a significant disadvantage in terms of cost of capital compared to MLPs who are at a lower threshold or have eliminated IDRs altogether. Roughly speaking, an incremental project must generate ~15.4% cash return of which ~7.4% (48%) would be distributed to ETE and ~8% to the limited partners. As of 8/24/12, RGP’s current yield of 8% is higher than of most of the other MLPs I cover. For example, 4.60% for Magellan Midstream Partners (MMP); 4.82% for Enterprise Products Partners L.P. (EPD); 4.93% for Plains All American Pipeline (PAA); 6.02% for Kinder Morgan Energy Partners (KMP); 6.20% for El Paso Pipeline Partners (EPB); 6.22% for Williams Partners (WPZ); 6.41% for Targa Resources Partners (NGLS); and 7.92% for Boardwalk Pipeline Partners (BWP). RGP’s yield is lower than the 8.52% offered by Buckeye Partner (BPL) and the 8.48% by its affiliate, Energy Transfer Partners (ETP). In light of the low coverage ratio, the relatively high leverage and my discomfort with the structural complexity surrounding ETE and ETP, I would stay on the sidelines despite the attractive yield.
    Wise Analysis
    A Closer Look at Energy Transfer Partners' Distributable Cash Flow as of 2Q 2012
  • By , 8/27/12
  • tags: ETP ETE MMP KMP
  • This article was submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool. On August 8, 2012, Energy Transfer Partners, L.P. (ETP) reported results of operations for 2Q 2012. Revenues, operating income, net income and earnings before interest, depreciation & amortization and income tax expenses (EBITDA) were as follows: Period:: 2Q12 2Q11 1H12 1H11 Revenues 1,240 1,628 2,546 3,316 Operating income 289 370 543 634 Net income 124 157 1,250 404 EBITDA 357 384 1736 845 Adjusted EBITDA 466 388 1,002 859 Weighted average units outstanding (million) 231 210 229 202 Table 1: Figures in $ Millions except shares outstanding Segment contribution to EBITDA was as follows: Period:: 2Q12 2Q11 1H12 1H11 Intrastate transportation and storage 157 172 349 344 Interstate transportation 184 83 297 164 Midstream 93 95 194 171 NGL transportation and services 39 25 74 25 Retail propane and other related 2 12 90 155 All other (9) 1 (3) 2 Total Segment Adjusted EBITDA 466 388 1,002 859 Table 2: Figures in $ Millions The Intrastate Transportation segment generated lower gross margins both in 2Q12 vs. 2Q11 and in 1H12 (first half of 2012) vs. 1H11. This was partially offset by lower operating expenses. Volumes transported and Segment Adjusted EBITDA generated by the Interstate segment increased both in 2Q12 vs. 2Q11 and in 1H12 vs. 1H11. Volumes increased primarily due to additional transported volumes related to the expansion of the Tiger pipeline, which went in service in August 2011, and Segment Adjusted EBITDA increased due to the acquisition of a 50% interest in Citrus on March 26, 2012 ($77 million was attributable to Citrus in 2Q12 and $81.3 million in 1H12). The remainder of the increase in Segment Adjusted EBITDA resulted from incremental reservation fees from increased contractual commitments related to the Tiger pipeline expansion and from the 50% interest in the Fayetteville Express Pipeline. On January 12, 2012, ETP contributed its propane operations, excluding the cylinder exchange business, to AmeriGas Partners, L.P. (APU). ETP received ~$1.46 billion in cash and ~29.6 million APU units (which ETP is obligated to hold until January 2013). APU assumed ~$71 million of debt related to the propane operations. ETP recognized a gain on deconsolidation of $1.06 billion.  Investors should note that the propane business is not considered a discontinued operation.  Rather, subsequent to the APU transaction propane results are reflected via ETP’s investment in APU and are accounted for under the equity method. ETP recorded equity in losses related to APU of $36.4 million and equity in earnings of $3.1 million for the three and six months ended 6/30/12, respectively. Propane segment results for 1H 2012 are harder to understand because they are comprised of 11 days of consolidated propane business activity and ~170 days of propane activity measured using the equity method. Given quarterly fluctuations in revenues, working capital needs and other items, it makes sense to review trailing 12 months (“TTM”) numbers rather than quarterly numbers for the purpose of analyzing changes in reported and sustainable distributable cash flows. 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 the trailing 12 months (“TTM”) period ending 6/30/12 was $5.30 per unit ($1,172 million), up 3% from $5.14 per unit ($1,005 million) for the TTM ending 6/30/11. 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 through 6/30/12 generates the comparison outlined in Table 3 below: 12 months ending: 6/30/12 6/30/11 Net cash provided by operating activities 1,304 958 Less: Maintenance capital expenditures (139) (105) Less: Working capital (generated) (217) - Less: Net income attributable to noncontrolling interests (44) (8) Sustainable DCF 905 845 Add: Net income attributable to noncontrolling interests 44 8 Working capital used - 199 Risk management activities 179 (40) Other 45 (6) DCF as reported 1,172 1,005 Table 3: Figures in $ Millions The principal difference between reported DCF and sustainable DCF in Table 3 relates to ETP’s risk management activities. In deriving its reported DCF, ETP adds back losses from risk management activities. This item totals $179 million in the TTM ended 6/30/12, the bulk of which is comprised of unrealized losses on interest rate swaps and commodity derivatives, as well as fair value adjustments on inventory. I do not add back these losses when calculating sustainable DCF. I also deducted $44 million to reflect Regency Energy LP’s (RGP) interest in Lone Star. Coverage ratios continue to be below 1.0 as indicated in Table 4 below: 12 months ending: 6/30/12 6/30/11 Total distributions $1,219 $1,096 Coverage ratio based on reported DCF 0.96 0.92 Coverage ratio based on sustainable DCF 0.74 0.77 Table 4 Incentive distributions to Energy Transfer Equity, L.P. (ETE), ETP’s general partner are included and accounted for 34.6% of total distributions for the TTM ended 6/30/12 and 36.3% for the comparable prior year period. The low coverage ratio of sustainable DCF is a warning signal. 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 12 months ending: 6/30/12 6/30/11 Net cash from operations, less maintenance capex, less net income from non-controlling interests, less distributions (54) (243) Capital expenditures ex maintenance, net of proceeds from sale of PP&E (1,672) (1,260) Acquisitions, investments (net of sale proceeds) (465) (1,951) Other CF from financing activities, net (26) (4) (2,217) (3,458) Cash contributions/distributions related to affiliates & noncontrolling interests 16 568 Debt incurred (repaid) 1,442 1,575 Partnership units  issued 790 1,348 Other CF from investing activities, net 23 20 2,273 3,510 Net change in cash 56 52 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 in both periods. Distributions in both TTM periods were financed with debt and equity. Following the $5.3 billion acquisition of Sunoco, Inc. (SUN), ETP will further reduce its dependence on natural gas and become a transporter of heavier hydrocarbons like crude oil, NGLs, and refined products. However, in an article dated May 3, 2012, I noted that I cannot understand how the SUN acquisition could be immediately accretive to ETP. Ray Merola, a fellow contributor, initiated a conversation with management representatives and published a well-written article dated July 27 concluding that the transaction was accretive to the tune of $88 million. Having adjusted my numbers to reflect input from that article, and having incorporated recent data from the Form 10-Q reports for 6/30/12 filed by SUN and SXL, I can see that, under certain assumptions, the acquisition can be accretive and present my analysis in Table 7. A quick recap is in order before proceeding to Table 7. Acquisition consideration consists of $25.00 of cash and 0.5245 ETP common units for each of the ~106 million fully diluted SUN shares. So the cash portion at $25 per SUN share comes to $2,650 million (50% of the announced $5.3 billion price tag). In addition, ETP will assume SUN’s debt which, as of 6/30/12, amounted to ~$990 million, net of the debt owed by Sunoco Logistics Partners L.P. (SXL). Another key parameter to keep in mind before the reviewing the analysis presented in Table 7 is the manner in which DCF is apportioned between the partners and the holder of Incentive Distribution Rights (“IDR”). ETE receives distributions both as a partner (it holds a general partner interest and limited partner interests) and as the sole owner of the IDRs. Based on my reading of agreements, ETE is entitled to IDR distributions according to the waterfall chart shown in Table 6. The chart is applied to the current distribution rate of $0.89375 per quarter ($3.575 per annum): Table 6: Figures in $ except for percentages To support the issuance of an additional LP unit that receives distributions of $0.89375 per quarter ($3.575 per annum), ETP must generate, by my calculations, an additional $1.4138 per quarter ($5.655 per annum) of DCF.  Hence, the cash required by ETP to support distributions for the 71.1 million additional shares depicted in Table 7 totals $402 million, of which $148 million is for the IDRs (before the IDR give-back). Event Transaction Financing Cash Flow Impact (next ~3 years) Notes SUN debt assumed (net of SXL debt ) 989 per Forms 10-Q for 6/30/12: SUN debt =2,548;  SXL debt = 1,559 Add: cash consideration portion 2,650 Consideration consists of $25.00 of cash and 0.5245x ETP common units per SUN share; $25 per share x 106m SUN shares=$2,650 Less cash from refinery divestitures (250) ETP data (per webcast) Less cash & cash equivalents on SUN balance sheet (1,884) Less: net proceeds from units issued July 3, 2012 (680) After an assumed $11m in commissions Net increase in debt and cash flow impact per annum 825 (50) I assume 6% cost of debt 15.5m units issued July 3, 2012 (55) 15.5m units issued at $44.57; Net proceeds =~$680m; $3.575 distribution per unit per annum = $55m in total 55.6m units to be issued to SUN shareholders (199) 0.5245 ETP common units per SUN share x 106m SUN shares=55.6m ETP units; $3.575 distribution per unit per annum=$199m per annum ETE IDRs (148) For every $3.575 distributed to LPs, $5.655 of cash is needed (see Table 6) ETE relinquishment of $210m in IDR over 3 yrs. 70 ETP’s April 30 presentation of the SUN acquisition Additional distributions required (332) At $3.575 per annum Other items: SUN retail gasoline EBITDA 261 ETP’s April 30 presentation of the SUN acquisition SUN retail gasoline maintenance cap ex (70) per SUN 12/31/11 Form 10-K, p51 and per range of $70-80 million provided at the webcast SUN distributions from SXL (pretax) 97 ETP’s April 30 presentation of the SUN acquisition Operational synergies 70 ETP data (estimate provided at the webcast) Total other items: 358 Net cash flow impact: (24) Table 7: Figures in $ Millions I noted above that, under certain assumptions, the acquisition can be accretive. For example, if proceeds of the recent 15.5 million share equity issuance were deemed allocated for other purposes (i.e., not the SUN acquisition) and the $680 million gap would be funded by additional debt at a 6% interest rate the numbers would swing from $24 million dilution to a $23 million accretion. But it seems to me that in any event the accretion from this transaction will be minimal. Not only that, but operational results will have to show substantial improvement to make up the $70 million shortfall that will arise when ETE’s $210 million of aggregate IDR relinquishment expires in 3 years. In addition to my discomfort with the SUN acquisition, the 1Q12 and 2Q12 results and the fact that distributions are being funded with debt and equity, I am also troubled by the sheer complexity of the ETP story. It has announced acquisitions in excess of $10 billion over an 18 months period, it will own a retail gasoline business which is non-strategic and does not fit well structure-wise because it is a corporation and is subject to corporate taxes, and it must dispose of aging refineries. The complexities created by using ETP for some acquisitions and ETE for others need to be untangled and, in attempting to do so, additional structures are being created. I find it difficult to follow the logic, economics and implications of the recent transaction, announced 6/15/12, whereby ETE and ETP agreed that following the closing of the SUN acquisition: (1)  ETE will contribute its interest in Southern Union into an ETP-controlled entity in exchange for a 60% equity interest in the new entity, to be called ETP Holdco Corporation (“Holdco”); (2)  ETP will contribute its interest in Sunoco to Holdco and will retain a 40% equity interest in Holdco. I am also unsure about the logic, economics and implications of: (3)  SUN contributing its interests in SXL to ETP in exchange for 50.7 million Class F Units representing ETP limited partner interests plus an additional number of such to be determined based upon the amount of cash contributed to ETP by SUN at the closing of the merger; and (4)  The Class F Units entitlement to 35% of the quarterly cash distributions generated by ETP and its subsidiaries other than Holdco, subject to a maximum cash distribution of $3.75 per Class F Unit per year. As of 8/17/12, ETP’s current yield of 8.17% is higher than almost all the other MLPs I cover. For example: the 4.55% for Magellan Midstream Partners (MMP), 4.71% for Enterprise Products Partners L.P. (EPD), 4.85% for Plains All American Pipeline (PAA), 5.96% for Kinder Morgan Energy Partners (KMP), 6.18% for Williams Partners (WPZ); 6.20% for El Paso Pipeline Partners (EPB); 6.31% for Targa Resources Partners (NGLS); 7.87% for Buckeye Partner (BPL); and 7.89% for Boardwalk Pipeline Partners (BWP). I am long both ETP and ETE, but in light of the low coverage ratio, the 1Q 2012 and 2Q 2012 results and my sense of discomfort with the structural complexity, I have already reduced, and may further reduce, my ETP position.
    Wise Analysis
    A Closer Look at Suburban Propane Partners' Distributable Cash Flow as of 3Q FY2012
  • By , 8/7/12
  • tags: NRGY SPH APU UGI
  • This article was submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool. SPH markets and distributes fuel oil, kerosene, diesel fuel and gasoline to residential and commercial customers, and is now the third largest retail marketer of propane in the United States, measured by retail gallons sold. On August 1, 2012, Suburban Propane Partners (SPH) consummated its acquisition of the retail propane business of Inergy L.P. (NRGY) in exchange for consideration of ~$1.8 billion consisting of (i) $1 billion in newly issued notes; (ii) $184.8 million in cash to NRGY note holders; and (iii) $590 million of new SPH units distributed to NRGY, all but $5.9 million of which will subsequently be distributed by NRGY to its unit holders. The notes and cash were issued and paid to holders of ~$1.2 billion NRGY notes. In addition, SPH paid ~$65 million to these note holders as a consent payment. SPH typically sells ~ 2/3 of its retail propane volume and ~ 3/4 of its retail fuel oil volume during the peak heating season of October through March.  In an article dated 4/21/12, I noted that fiscal 2012 will not look good compared to fiscal 2011. Indeed, a review of the first 9 months of the fiscal year illustrates the difficult business environment faced by SPH: 9 months ended : 6/30/12 6/30/11 6/30/10 Propane 667 787 758 Fuel oil and refined fuels 92 124 121 Natural gas and electricity 52 68 59 All other 26 29 30 Total Revenues 837 1,009 969 Cost of products sold 481 572 505 Operating 203 214 222 General and administrative 40 37 47 Restructuring, severance & pension settlement charges 6 2 - Depreciation and amortization 24 26 23 Total Costs and expenses 753 851 798 Operating income 84 158 171 Table 1: Figures in $ Millions; fiscal year ends Sep 30. Retail propane gallons sold in third fiscal quarter ended 6/30/12 (3Q FY2012) decreased ~ 5.6 million gallons, or 10.3%, to 49.0 million gallons compared to 54.6 million gallons in the prior year third quarter. Sales of fuel oil and other refined fuels decreased approximately 1.3 million gallons, or 23.2%, to 4.3 million gallons during the third quarter of fiscal 2012, compared to 5.6 million gallons in the prior year third quarter. The most significant factor cited by management as impacting volumes in both segments during the third quarter of fiscal 2012 was a near-record warm April 2012, which added to the effects of a record warm second quarter of fiscal 2012, across the SPH’s service territories. SPH has maintained its distribution per unit at $3.41 ($0.8525 per quarter) for the last 9 consecutive quarters despite deteriorating business fundamentals. At 8.5%, SPH offers an enticing distribution yield.  However, investors should review SPH’s results of operations as of its third fiscal quarter ended 6/30/12 (3Q FY2012) and the implications of SPH’s $1.8 billion acquisition of NRGY’s propane business consummated on 8/1/12, in an attempt to ascertain whether the distribution is sustainable. Distributable cash flow (“DCF”) is a quantitative standard viewed by investors, analysts and the general partners of many master limited partnerships (“MLPs”) as an indicator of the MLP’s ability to generate cash flow at a level that can sustain or support an increase in quarterly distribution rates. Since DCF is not a Generally Accepted Accounting Principles (“GAAP”) measure, its definition is not standardized. In fact, as shown in a prior article, each MLP may define DCF differently. SPH does not define DCF at all and the only non-GAAP measure it reports is adjusted EBITDA. A review of its cash flows and the sustainability of its distributions can still be performed, albeit without a comparison to reported DCF. Given quarterly fluctuations in revenues, working capital needs and other items, it makes sense to review trailing 12 months (“TTM”) numbers rather than quarterly numbers for the purpose of ascertaining whether distributions are sustainable DCF and whether they were funded by additional debt, by issuing additional units or other sources of cash that I consider non-sustainable. A good starting would be to compare sustainable cash flow to partnership distributions: 12 months ended : 6/30/12 6/30/11 Net cash provided by operating activities 96 136 Less: Maintenance capital expenditures (11) (10) Less: Working capital (generated) (13) - Sustainable DCF 73 126 Partnership distributions 121 120 Distribution Coverage 0.60 1.05 Table 2: Figures in $ Millions except Distribution Coverage; fiscal year ends Sep 30. Table 2 indicates that for the TTM ending 6/30/12 sustainable DCF fell significantly short of covering distributions. The gap has not been filled by issuing debt or equity, but rather by reducing cash reserves. This can be seen from a simplified cash flow statement in Table 3 below: Simplified Sources and Uses of Funds: 12 months ended : 6/30/12 6/30/11 Net cash from operations, less maintenance capex, less distributions (35) 5 Capital expenditures ex maintenance, net of proceeds from sale of PP&E (6) (7) Acquisitions, investments (net of sale proceeds) (7) Debt incurred (repaid) (4) - Net change in cash (46) (9) Table 3: Figures in $ Millions; fiscal year ends Sep 30. As of 6/30/12 SPH’s balance sheet was strong with equity capital at $896 million (down from $976 million in the prior year) and long term debt only at $348 million (unchanged from a year ago). The EBITDA multiple for the TTM ending 6/30/12 was conservative 3.4x. There were no intangible assets to speak of. The acquisition of NRGY’s retail propane business was consummated after the end of the fiscal quarter and its results of operation are not reflected in Tables 1-3. They are provided in a pro-forma statement issued 8/6/12 and indicate deteriorating margins, operating income and net income: Inergy Propane, LLC and Subsidiaries   9 months ended : 6/30/12 6/30/11 Propane 1,132 1,188 Other 403 367 Total revenue 1,535 1,555 Propane 851 821 Other 311 281 Total cost of product sold: 1,163 1,102 Expenses: Operating and administrative 218 213 Depreciation and amortization 88 88 Loss on disposal of assets 6 5 Operating income 61 147 Other income (expense): Interest expense, net (1) (1) Other income 1 0 Income before income taxes 61 146 Benefit (provision) for income taxes 0 (1) Net income 62 145 Table 4: Figures in $ Millions The reason the interest expense in Table 4 is so low is that the ~$1 billion of debt assumed by SHP is not on the balance sheet of Inergy Propane, so the interest expense does not appear on the income statement. Adding depreciation and amortization to operating income for the 9 months period ending 6/30/12 gives us ~$150 million of operating cash flow. From this we should deduct maintenance capital expenditures (say $8 million), interest expense on $1 billion of debt for 9 months (say $57 million), leaving ~$85 million. The $590 million worth of SPH units will require distributions of ~$38 million (on a 9-month basis), so there should be an excess of ~$47 million ($63 million annualized) which makes the deal accretive for SPH unit holders. If, in addition, SPH can extract operating efficiencies from the combined businesses, sustainable DCF may cover distributions. With the units trading at around $40, this may be an opportune time to establish or increase a position in SPH. Unlike some of the other MLPs I have covered, including for example: El Paso Pipeline Partners (EPB), Enterprise Products Partners (EPD), Magellan Midstream Partners (MMP), Targa Resources Partners (NGLS), Plains All American Pipeline (PAA), and Williams Partners (WPZ), I don’t see much potential for growth in distributions. However, the yield is already at 8.5% and if the coverage ratio improves there is possibility for some capital appreciation.
    Wise Analysis
    Correlation Between Master Limited Partnership Returns And Oil Prices – May 2012 Could Have Been Worse
  • By , 6/25/12
  • tags: AMZX EPB EPD PAA KMP
  • Correlation between Master Limited Partnership returns and oil prices-May 2012 could have been worse In an article published January 19, 2012, I looked at the relationship between returns of master limited partnerships (“MLPs”)and oil prices and showed that while prior to 2008 the two were largely uncorrelated, reality has markedly changed over the last few years. Beginning around December 2008, the data indicates a significant positive correlation between MLP returns and oil prices. I suggested this correlation be carefully considered and taken into account in any attempt to build a balanced investment portfolio and pointed out that if the recent pattern of close correlation continues, there appears to be a significant risk that a decline in oil will be accompanied by a decline in the per unit prices of energy MLPs.
    Wise Analysis
    A Closer Look at Annaly Capital Management’s Cash Flows
  • By , 6/22/12
  • tags: NLY EPD WPZ ETP KMP
  • This article was submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool. My prior articles focused on master limited partnerships (“MLPs”), an area I have long followed and invested in. My concern with overly concentrating my portfolio in MLPs has led me to examine mortgage Real Estate Investment Trusts (“mREITs”) as an alternative yield producing vehicle. Indeed, the current dividend yields on some mREITs exceed the distribution yields on many MLPs including El Paso Pipeline Partners (EPB), Enterprise Products Partners (EPD), Energy Transfer Partners (ETP), Kinder Morgan Energy Partners (KMP), Plains All American Pipeline (PAA), and Williams Partners (WPZ).
    Wise Analysis
    A Closer Look at Regency Energy Partners' Distributable Cash Flow as of 1Q 2012
  • By , 6/6/12
  • tags: RGP WPZ EPB NGLS SUG
  • This article was submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool. Revenues generated by Regency Energy Partners LP (RGP) in 1Q 2012 decreased 3.2% vs. the prior quarter and were up 128% vs. 1Q 2011 (by comparison, revenues in 1Q 2011 decreased 1.7% vs. 4Q 2010 and were up 4.1% over 1Q 2010).  Earnings before interest expense, depreciation & amortization and income taxes (EBITDA) increased 23.4% in 1Q 2012 vs. the prior quarter and were up 47.6% over the comparable prior year period. RGP’s definition of Distributable Cash Flow (“DCF”) and a comparison to definitions used by other master limited partnerships (“MLPs”) are described in an article titled “Distributable Cash Flow (“DCF)” . Using that definition, DCF for the trailing 12 months (“TTM”) period ending 3/31/12 was $329 million ($2.18 per unit), up from $247 million ($1.96 per unit) in the comparable prior year period. 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.
    A Closer Look at Boardwalk Pipeline Partners’ Distributable Cash Flow as of 1Q 2012
  • By , 6/4/12
  • tags: BWP KMP PAA EPD WPZ
  • This article was submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool. In 1Q 2012, Boardwalk Pipeline Partners, LP (BWP) increased its revenues 5.4% vs. the prior quarter and 0.6% vs. 1Q 2011 (by comparison, revenues in 1Q 2011 increased 3% vs. 4Q 2010 and were up 3.5% over 1Q 2010).  Earnings before interest expense, depreciation & amortization and income taxes (EBITDA) increased 15.6% in 1Q 2012 vs. the prior quarter, were up 5.4% over the prior year and were in line with consensus estimates for the quarter. 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 the trailing 12 months (“TTM”) period ending 3/31/12 was $407 million ($2.31 per unit), down from $437 million in the comparable prior year period ($2.58 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.
    Wise Analysis
    A Closer Look at Suburban Propane Partners' Distributable Cash Flow as of 2Q FY2012
  • By , 6/1/12
  • tags: SPH NRGY APU 8097
  • This article was submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool. Suburban Propane Partners (SPH) markets and distributes fuel oil, kerosene, diesel fuel and gasoline to approximately 48,000 residential and commercial customers in the northeast region of the United States. It is one of the largest retail marketers of propane in the United States, measured by retail gallons sold. SPH typically sells ~ 2/3 of its retail propane volume and ~ 3/4 of its retail fuel oil volume during the peak heating season of October through March.  In an article dated 4/21/12, I noted results for the second half the heating season in fiscal 2012 (i.e., quarter ended 3/31/12) will, based on the warmer than usual weather, compare unfavorably with the prior year period and that would indicate fiscal 2012 will also not look good compared to fiscal 2011. A review of the first 6 months of the fiscal year illustrates the difficult business environment faced by SPH: 6 months ended : 3/31/12 3/31/11 3/31/10 Propane 524 618 603 Fuel oil and refined fuels 75 102 101 Natural gas and electricity 40 52 46 All other 19 21 21 Total Revenues 658 792 771 Cost of products sold 392 446 399 Operating 137 145 153 General and administrative 26 25 34 Restructuring charges and severance costs 2 - Depreciation and amortization 15 17 14 Total Costs and expenses 571 635 600 Operating income 86 158 171 Table 1: Figures in $ Millions; fiscal year ends Sep 30. In the past 12 months the unit price has dropped ~27% (from $52.77 to $38.51 on 5/25/12). SPH has maintained its distribution per unit at $3.41 ($0.8525 per quarter) for the last 8 consecutive quarters despite deteriorating business fundamentals. At 8.85%, SPH offers an enticing distribution yield.  However, investors should review SPH’s results of operations as of its second fiscal quarter ended 3/31/12 (2Q FY2012) in an attempt to ascertain whether the distribution is sustainable. This review should be undertaken independently of looking into the implications of SPH’s $1.8 billion acquisition of NRGY’s propane business announced on 4/26/12, Distributable cash flow (“DCF”) is a quantitative standard viewed by investors, analysts and the general partners of many master limited partnerships (“MLPs”) as an indicator of the MLP’s ability to generate cash flow at a level that can sustain or support an increase in quarterly distribution rates. Since DCF is not a Generally Accepted Accounting Principles (“GAAP”) measure, its definition is not standardized. In fact, as shown in a prior article, each MLP may define DCF differently. SPH does not define DCF at all and the only non-GAAP measure it reports is adjusted EBITDA. A review of its cash flows and the sustainability of its distributions can still be performed, albeit without a comparison to reported DCF. Given quarterly fluctuations in revenues, working capital needs and other items, it makes sense to review trailing 12 months (“TTM”) numbers rather than quarterly numbers for the purpose of ascertaining whether distributions are sustainable DCF and whether they were funded by additional debt, by issuing additional units or other sources of cash that I consider non-sustainable. A good starting would be to compare sustainable cash flow to partnership distributions: 12 months ended : 3/31/12 3/31/11 Net cash provided by operating activities 100 148 Less: Maintenance capital expenditures (10) (11) Less: Working capital (generated) (13) - Sustainable DCF 77 137 Partnership distributions 121 120 Distribution Coverage 0.64 1.15 Table 2: Figures in $ Millions except Distribution Coverage; fiscal year ends Sep 30. Table 2 indicates that for the TTM ending 3/31/12 sustainable DCF fell significantly short of covering distributions. The gap has not been filled by issuing debt or equity, but rather by reducing cash reserves. This can be seen from a simplified cash flow statement in Table 3 below: Simplified Sources and Uses of Funds: 12 months ended : 3/31/12 3/31/11 Net cash from operations, less maintenance capex, less distributions (31) 18 Capital expenditures ex maintenance, net of proceeds from sale of PP&E (7) (4) Acquisitions, investments (net of sale proceeds) (18) Debt incurred (repaid) (2) - Net change in cash (41) (4) Table 3: Figures in $ Millions; fiscal year ends Sep 30. As of 3/31/12 SPH’s balance sheet was strong with equity capital at $931 million and long term debt only at $348 million, representing a conservative 3.3x EBITDA multiple for the TTM ending 3/31/12. There were no intangible assets to speak of. On 4/26/12 SPH announced an agreement to purchase the propane operations of Inergy L.P. (NRGY) in exchange for approximately $1.8 billion, comprised of $600 million in the form of ~13.7 million common units (now worth less than $600 million), $200 million in cash and $1 billion in the form of an exchange of NRGY’s outstanding senior notes for new SPH senior notes. Assuming the distribution rate remains unchanged 13.7 million units will require ~$47 million of cash per annum. I estimate $1.15 billion of debt will be raised; $1 billion for the above-mentioned exchange and $150 million ($200 million net of $50 million of the cash already on the balance sheet) for the cash portion of the acquisition. Assuming an interest rate of 7%, the new debt will require ~$81 million of annual interest payments, bringing the total requirement to just shy of $130 million per annum. The most difficult variable to estimate is what can NRGY’s propane operations generate for SPH. For the 6 months ending 3/31/12, NRGY generated gross profit on propane operations equivalent to ~24% of propane revenues. In the same period, SPH’s propane operations generated operating profit (i.e., after deducting from gross profit operating expenses, general & administrative expenses, and depreciation) equivalent to ~22% of propane revenues. This indicates to me that SPH can run the propane business much more efficiently than NRGY and, given that NRGY’s propane business generated over $1.4 billion in revenues in the TTM ending 3/31/12, the additional cash it can generate via an acquisition of this scale could significantly exceed the ~$130 million required to breakeven. Nevertheless, I don’t consider this to be a sufficiently solid basis for initiating a position in SPH and remain concerned about the challenges (declining volumes, declining margins) in the retail propane business. I don’t see SPH providing much of an upside vs. some of the other MLPs I have covered, including for example: El Paso Pipeline Partners (EPB), Enterprise Products Partners (EPD), Magellan Midstream Partners (MMP), Targa Resources Partners (NGLS), Plains All American Pipeline (PAA), and Williams Partners (WMB).
    Wise Analysis
    A Closer Look at Buckeye Partners' Distributable Cash Flow as of 1Q 201
  • By , 5/22/12
  • tags: BPL KMP PAA EP EPP
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool I sounded a first note of caution regarding Buckeye Partners (BPL) in an article dated December 19, 2011 (price per unit was $63.00), a second note of caution in an article dated February 13, 2012 (price per unit was $62.20), and a third in an article dated April 19, 2012 (price per unit was $54.04). On May 18, 2012 BPL closed at $45.71, a 28.5% decline from the $63.98 price at year-end 2011. This compares to a ~6.8% decline in the Alerian MLP Index on a price-return basis over this period. BPL’s distribution yield has increased from ~6.7% to almost 9.1%. But management suspended further distribution increases and this article looks at whether this level of distributions sustainable. Given quarterly fluctuations in revenues, working capital needs and other items, it makes sense to review trailing 12 months (“TTM”) numbers rather than quarterly numbers for the purpose of analyzing changes in reported and sustainable distributable cash flows.
    Wise Analysis
    A Closer Look at Plains All American Pipeline’s Distributable Cash Flow as of 1Q 2012
  • By , 5/21/12
  • tags: PAA KMP MMP EEP EP
  • Submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool Revenues in 1Q 2012 increased 3.8% vs. the prior quarter and 19.8% vs. 1Q 2011 (by comparison, revenues in 1Q 2011 increased 6.4% vs. 4Q 2010 and were up 25.6% over 1Q 2010).  Earnings before interest expense, depreciation & amortization and income taxes (EBITDA) in 1Q 2012 decreased 1% vs. the prior quarter and were up 17.2% over the prior year period. However, adjusted EBITDA in 1Q12 was 18% above the $400 million mid-point of the guidance provided by management for that quarter. The Partnership’s first-quarter operating results was not impacted by the acquisition of the Canadian natural gas liquids business from a subsidiary of BP Corporation North America, Inc., which closed effective April 1, 2012. Given quarterly fluctuations in revenues, working capital needs and other items, it makes sense to review trailing 12 months (“TTM”) numbers rather than quarterly numbers for the purpose of analyzing changes in reported and sustainable distributable cash flows.
    Wise Analysis
    A Closer Look at Energy Transfer Partners' Distributable Cash Flow as of 1Q 2012
  • By , 5/15/12
  • tags: EPD KMP KMI PAA ETP WPZ
  • This article was submitted by Ron Hiram of Wise Analysis using our Trefis Contributors tool. In an article titled “Distributable Cash Flow (“DCF”) I present the definition of DCF used by Energy Transfer Partners, L.P. (ETP) and provide a comparison to definitions used by other MLPs. Using ETP’s definition, DCF for the trailing 12 months (“TTM”) period ending 3/31/12 was $5.17 per unit ($1,120 million), down 6% from $5.50 per unit ($982 million) for the TTM ending 3/31/11. In this article I compare reported DCF to what I call sustainable DCF, review distribution coverage ratios based on reported and sustainable DCF, look at how distributions were funded, and discuss issues relating to ETP’s performance in 1Q 2012 and recent developments.

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