midstream 2014 recap and 2015 year ahead january 9, 2015
TRANSCRIPT
Midstream 2014 Recap and 2015 Year Ahead January 9, 2015
Becca Followill Senior Managing Director
713-366-0557 [email protected]
James Carreker, CFA
Director 713-366-0558
Please see important disclosures beginning on page 55
Summary
2
Starting the New Year, it’s helpful to recap trends of the past year, what worked and didn’t, and implications for the year ahead. 2015 will be largely shaped by the commodity collapse at year-end 2014. The largest infrastructure boom in our lifetime stands to stub its collective toe and take a collective pause and depending on how prices shake out, could turn into a bust with some recently completed assets going idle. While the word “Opportunity” best described 2014 (excluding Q4 of course), the word “Uncertainty” we think best describes 2015. E&Ps are reworking budgets, MLPs are waiting on those outcomes, and no one has conviction on commodity prices.
At the beginning of this piece we look back at the key themes of ‘14, discuss what we think will be hot (and not) in ‘15 and list some of the headwinds and tailwinds facing the group.
We then break the piece down into six sections: Sector Performance, Commodity Pricing Commentary, Infrastructure Build, M&A, Capital Markets and Money Flows, and Valuation.
Sector Performance
The Alerian MLP index was relatively flat for 2014, with a -1% price change for the year. The index underperformed the S&P 500 by ~12% (S&P +11.4% in ’14). After dividends, the AMZ underperformed the S&P 500 by 6.6%.
Top 3 performing sectors were Refinery Logistics MLPs, Natural Gas MLPs and Diversified Midstream MLPs.
Bottom 3 performing sectors were E&P MLPs, Agricultural Products MLPs and Oilfield Services MLPs.
MLP IPOs in ‘14 were also relatively flat on the year with an average gain of 3%. Note that 11 of 20 names were negative on the year.
Valuation
Top Picks: Our top picks for ’15 are CQP – $31.18 – Buy – $41 PT, CQH – $22.68 – Buy – $32 PT, EQM – $82.33 – Buy – $107 PT, and EPD – $34.44 – $44 PT. With CQP and CQH, they have highly contracted cash flows with no commodity sensitivity and visibility to substantial distribution growth in ‘17 as LNG’s projects are completed. EQM has double digit distribution growth for the next 5 years, minimal leverage, no commodity sensitivity and volumes largely gas pipeline driven. EPD is a solid standby, with thick coverage, the ability to grow their distribution in almost every scenario, and a cost of capital advantage by not having a general partner.
Summary (cont’d)
3
Commodity Pricing Commentary
NGLs 2014 – Biggest story of the year was collapse in NGL prices following the crude drop in Q4’14. NGL prices got an artificial boost in Q1 on cold weather and surging propane prices. But the propane shortage quickly turned into a glut – just like the rest of the NGL barrel. And NGLs took another major leg down with oil in October.
And the #2 story was ethane decoupling from methane beginning mid summer. Common view was that methane would provide a floor for ethane, as producers could keep ethane in the gas stream via ethane rejection, but recently ethane has traded to as low as 70% of its methane equivalent value.
Despite the composite NGL barrel trading at its lowest levels since 2002 (currently 40c/gal – even in Dec ’08 with crude at $40/bbl NGLs traded only as low as 45c/gal), we are modestly bullish on NGL prices. While we see little upside to ethane, propane exports and a modest increase in crude prices should provide some relief:
• Ethane: Still capped at maximum of methane prices. At our $3.25/mcf gas price assumption, that’s 21c/gal. We think ethane will trade below that given the incentive to realize higher propane prices and limits on ethane rejection due to gas pipeline BTU limitations.
• Propane: Export facilities provide near term uplift. With propane inventories at all-time highs and ~20 mmbbls over 5-year averages, the addition of SXL’s Mariner East and Mariner South and EPD’s Gulf Coast Expansion in early ’15 should provide an additional 300 mbpd of export capacity to soak up a flooded local market.
• C4+: Higher crude price forecast should provide tailwind. Exacerbating the NGL barrel decline has been that in addition to lower crude prices, butanes and pentanes have also been trading lower on a relative basis – butanes now at 53% of crude and pentane at 78% vs. 2014 averages of 55% and 89%. Assuming the heavier portion of the barrel returns to historical trading averages on a relative basis and we see crude improve to $60/bbl in ’15, we should see some improvement in C4+ pricing.
For ‘15, we are assuming that NGLs trade at 55c/gal or ~38.5% of crude oil, about 35% above their current prices.
Summary (cont’d)
4
Commodity Pricing Commentary (cont’d)
Crude Oil – Year-end Collapse: While ‘14 crude oil prices averaged $93/bbl, down only 5% from ‘13, prices have been in a freefall since early October to now sub $50/bbl. And the market moved from backwardated to contango in early October. U.S. oil production rose another 1.2 mbpd in ‘14, following a 1 mmbpd increase in ’13 and reached its highest level in almost 30 years (Feb ’86).
Natural Gas – Stellar start, dismal finish is the best way to describe ’14, with weather the driver of both (1Q 10% colder than normal and 4Q 6% warmer than normal). Storage swung from being 55% below the 5-year average at the first of April to basically normal by the end of the year. Those massive injections helped support gas prices, until there was no more room left at the inn. Total production rose a whopping 7% or 5 bcf/d. For ’15, although we have gas production growing by 4 bcf/d or +5%, we have the year-over-year rate of change slowing to 1% by March.
USCA Price Deck: Our commodity price assumptions along 12-month strip pricing (as of 1.7.15) are shown below. Our view is shaped by the following:
Source: USCA, Bloomberg
• Oil: The pain OPEC (basically Saudi) is inflicting to curb the shale revolution and weaken Russia and Iran in particular is also straining OPEC country budgets (most budgets need >$90 oil). Yes, Saudi has $750B or two years of reserves, but we think there is a limit to how long they’ll let this last. If the deficits starts to impact social programs, the risk of political instability rises materially. For the first time in an oil cycle, the primary marginal supplier of oil (U.S.) has a very steep decline curve (things will correct quicker). And, not much in the world is truly economic sub $60/bbl.
• NGLs: While we see an oversupply of ethane lasting at least several years, we think the additional ~250 mbpd of propane export capacity in Q1’15 and another 230 mbpd by Q4’15 will place upward pressure on propane prices.
• Gas: We are not too much above the current ‘15 gas strip of $2.98/mcf. At $3 gas in January, we think curtailments are likely, the pace of supply growth is likely to slow as rigs are dropped, and low prices should further stimulate demand.
USCA Commodity Price Assumptions
Gas ($/mcf) Oil ($/bbl) NGLs ($/gal) Gas ($/mcf) Oil ($/bbl) NGLs ($/gal)
USCA Assumptions $3.25 $60 $0.55 $3.75 $75 $0.65
12-month strip $2.98 $52 $0.42 $3.35 $58 $0.45
2015 2016
Summary (cont’d)
5
Infrastructure Build
2014 Trends – We tally almost $70B of projects announced during ’14 – a pretty staggering number. That includes only announcements from publicly traded companies for U.S. infrastructure projects >$100mm, where we can reasonably estimate costs (if not otherwise given) and where the project has a good likelihood of proceeding. Gas pipelines dominated the announcements, accounting for 53% of the potential capex spend, and the vast majority of that was for Appalachia take-away capacity.
Implications for 2015 – Midstream backlogs are chock full following the burst of activity in 2014. This is a year to digest and execute, particularly as we enter a major gas pipeline build cycle. Producer capex cuts have just now begun to trickle in, and E&Ps are only talking about ‘15 volumes right now, which are driven primarily by drilling that occurred in ‘14. The elephant in the room is what happens to ‘16 volumes following some meaningful drilling slowdowns in ‘15. For the Midstream guys, the ball is in the E&P’s court, and they just have to wait for their next move. We think Midstream companies are doing some serious scrubbing of capex budgets – how many fewer well connects, which projects can and need to be deferred, and how do they work with their E&P customers to help ease the pain?
Bright Spots – Four bright spots in an otherwise nasty commodity tape are the potential for much needed additional ethane export facilities; the likelihood of crude oil exports in ‘15 and the associated needed infrastructure; preliminary discussion of another major round of new ethylene crackers on the drawing boards for the end of this decade; and with gas prices at $3, higher gas demand and potential market-pull gas pipeline projects.
M&A
2014 Trends – Record year of M&A by a longshot, with $185B of transactions. Two deals dominate the numbers: KMI’s $70B buy in of KMP, KMR and EPB, and the $37B WPZ/ACMP merger. Excluding those two mega deals, it was still a record year. ‘14 saw announcements to take out 9 publicly traded MLPs, up from 4 in ‘13. Most interesting deals by far were Kinder buy in of KMP, EPB and KMR and Targa buyout of APL and ATLS – with both GPs capturing the LP depreciation tax shield.
Implications for 2015 – While we don’t think we’ll beat the record $185B of M&A in ’14, we do think ‘15 will be another big year, with four key dynamics at play: Low commodity prices; the big guys are doing it; asset grab under way; and a highly fragmented sector.
Summary (cont’d)
6
Capital Markets & Money Flows
2014 Trends – Most notable was that ‘14 saw the most capital markets activity ever, with $78B of debt and equity issued versus $68B in ‘13 and $66B in ‘12. IPO activity remained high, although slightly lower than the record ’13. In ‘14, $7.7B was raised through 20 IPOs vs. $8.5B in ’13 (21 IPOs). SHLX and AM led the charge with $1.1B and $1.2B raised, respectively, the largest MLPs IPOs to date. ATM programs continued to pick up steam with $5.6B raised through Q3’14, almost topping the $5.9B raised in all of ’13. MLP industry (including pure GPs) closed ‘14 with 134 publicly traded companies with market cap of $633B. That’s up from ~120 companies last year with a market cap of $590B and 36 companies ten years ago with market cap of $55B.
Implications for 2015 – Currently 15 S-1s pending for new MLPs, three times as many than this time last year, plus five more announced, but not yet filed MLPs. We are unsure when, if ever, the IRS will formally end their “pause”. And we are not sure if it really matters as they have begun PLRs for mainstream MLP assets, and the pause has done little to dampen a high level of activity in the space.
2014 Look Back
7
What Was Hot What Was NotShort Energy Crude Oil Prices
Condensate Exports Crude Oil Imports
Restructuring/Activists Vertical Integration
NGL Exports NGL Prices
Ethane Rejection Methane Floor for Ethane
Crude Basis Narrowing Appalachia Gas Basis
New Appalachia Infrastructure Haynesville, Rockies and Other Dry Gas
Natural Gas Pipelines Natural Gas Storage
M&A Bargain Deals
Permian and Utica Basins Mississippi Lime
U.S. LNG Contracts Canadian LNG Contracts
ATM Programs Overnight Equity
GP Multiples E&P MLPs and Royalty Trusts
Yield vs. Growth Valuations DCF Analysis
Gulf Coast Water Access & Storage Cushing
Energy Reform in Mexico OPEC Power
2014
2015 Look Forward
8
Likely Hot Likely NotMLP M&A Raising Distribution Growth Guidance
Midstream Project Deferrals Major New U.S. Infrastructure Projects
E&Ps Outsourcing Midstream Infrastructure Rig Count
Private Equity/E&P Midstream Asset Sales Marginal MLP IPOs
More Ethane Rejection
Ethane Export Plans
Crude Oil Exports
Gulf Coast Water Access
Monster Utica Wells Anything marginal at $65 oil and $3 gas
Rising Interest Rates Credit Ratings
2015
Crude Oil Imports
Ethane Prices
2015 Tailwinds and Headwinds
9
Tailwinds HeadwindsM&A Valuation Support Higher Cost of Equity
Still Cheap Cost of Debt Rising Interest Rates
Volume Growth on E&P's '14 Spend Lower '15 E&P Capex = Uncertainty for '16
Higher Refined Product Demand Global Growth Concerns
Large Infrastructure Backlog Potential Project Deferrals
Minimum Volume Commitments Higher Risk E&P Counterparties
Lower Capex Falling Coverage Ratios
Increased Propane Export Capacity Finite Market
First LNG Exports (late '15) Massive Utica Wells
Visibility of Future Petchem Expansions NGL Oversupply
Crude Oil Export Approval
Contango Crude Market
Heading into 2015
Crude Oil Prices
Fed
Fu
nd
s Ta
rget
Rat
e
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
4.0%
4.5%
5.0%
5.5%
-15%
-5%
5%
15%
25%
35%
45%
Ind
ex R
elat
ive
Per
form
ance
S&P and AMZ Performance in Rising Rate Environment
Fed Funds Target Rate S&P 500 AMZ Index
Rising Interest Rates – “Waiting Patiently”
Source: USCA, Bloomberg
10
For almost a year the Fed has been pointing towards mid-’15 as the most likely time to begin raising interest rates. The Fed has said they will “wait patiently” for the right time and do not expect to begin raising before April.
Unemployment is down to 5.8%, third quarter GDP was revised upward to 5.0%, and inflation is in check – all signs point to a 2015 raise.
Closest corollary we have to this is the ‘04-’06 period when a 1% Fed Funds rate was gradually increased by 25 bp increments to reach 5.25%. Over that two-year period the S&P 500 was stagnant for the first six months, but rose ~15% over the period. In contrast, MLPs rose 35% through the first 2% increase in the Fed Funds rate, but then fell 10% once the rate broached 3%.
Bottom right chart shows historical 10-year yields and the correlation between AMZ performance and yields. Expectations are that higher yields would indicate poor AMZ performance; however, over the last 15 years, this correlation has only been negative for ~1/3rd of the time.
Only noticeable correlation we’ve been able to parse out during periods of rising rates is that large caps seem to underperform due to their liquidity.
Implications for 2015
While we don’t see a meaningful impact for the weighted average cost of debt in the space, a rising interest rate environment adds fuel to a fire already being fed by low commodity prices and an uncertain commodity price outlook.
In addition, rising interest rates could have a negative impact on fund flows, which provided nice industry tailwinds for the past three years.
Sector Performance
11
29.6%
25.3%
24.2%
14.0%
11.4%
6.9%
6.5%
5.9%
5.9%
2.9%
-0.4%
-0.9%
-10.3%
-18.0%
-19.2%
-24.1%
-24.3%
-31.7%
-37.6%
-45.9%
-52.7%
-60% -50% -40% -30% -20% -10% 0% 10% 20% 30% 40%
Refinery Logistics MLPs
MSCI US REIT Index
Utility Index
Natural Gas MLPs
S&P 500 Index
Diversified Midstream MLPs
General Partners
Refined Products MLPs
Other MLPs
Propane MLPs
Yield Cos
Alerian MLP Index
Gathering & Processing MLPs
Refiner MLPs
Shipping MLPs
Coal/Mining MLPs
Oilfield Services MLPs
Natural Gas
Agricultural Products MLPs
Crude Oil
E&P MLPs
2014 Price Change
Source: Bloomberg, USCA, as of 12/31/14
12
The Alerian MLP index was relatively flat for 2014, with a -1% price change for the year. The index underperformed the S&P 500 by ~12% (S&P +11.4% in ’14). After dividends, the AMZ underperformed the S&P 500 by 6.6%.
In contrast to AMZ underperformance, Refinery Logistics and Natural Gas MLPs outperformed the S&P 500 by 18.2% and 2.6%, respectively.
Top 3 performing sectors were Refinery Logistics MLPs, Natural Gas MLPs and Diversified Midstream MLPs.
Bottom 3 performing sectors were E&P MLPs, Agricultural Products MLPs and Oilfield Services MLPs.
Not shown to the right, but ‘14 MLP IPOs were relatively flat on the year with an average gain of 3%. Note that 11 of 20 names were negative on the year.
Top 5 performing MLPs/GPs (price only) were: PSXP, TEP, MPLX, WGP and SUN, posting an average 64% gain. EQM made its third straight appearance in the top 10.
Bottom 5 performing MLPs/GPs (price only) were: RNO, NKA, MCEP, NSLP, and LINE, posting an average 74% decline. No surprise that 8 out of bottom 10 performers were E&P MLPs. RNO (coal /mining) and EROC made their third straight appearance with LNCO repeating as well.
Average year-end yield for the top ten in ‘14 was 3% vs. 20% for the bottom ten.
-80.2%
-79.9%
-72.4%
-69.2%
-67.1%
-66.3%
-65.6%
-63.0%
-59.4%
-58.5%
-85% -75% -65% -55% -45% -35% -25%
RNO
NKA
MCEP
NSLP
LINE
LNCO
BBEP
EROC
LGCY
LRE
Worst Performing MLPs in 20142014 Price Change
81.7%
71.9%
65.0%
52.4%
50.4%
50.1%
49.7%
47.1%
44.9%
40.9%
25% 35% 45% 55% 65% 75% 85%
PSXP
TEP
MPLX
WGP
SUN
OILT
EQM
TCP
EEQ
CAPL
Best Performing MLPs in 20142014 Price Change
Source: Bloomberg, USCA, as of 12/31/14
13
-10.0%
-1.9%
-0.9%
4.7%
7.5%
8.0%
11.4%
12.9%
13.1%
18.2%
23.3%
24.3%
25.3%
-15% -10% -5% 0% 5% 10% 15% 20% 25% 30%
Energy
Telecommunications
Alerian MLP Index
Materials
Industrials
Consumer Discretionary
S&P 500
Consumer Staples
Financials
Information Technology
Healthcare
Utilities
MSCI US REIT Index
Source: Bloomberg, USCA, as of 12/31/14
14 -100% -80% -60% -40% -20% 0%
ALDW
OKS
TLP
CVRR
CPLP
TNH
AMID
CCLP
QEPM
EXLP
DLNG
MEMP
BWP
MEP
ATLS
MMLP
CMLP
USAC
EVEP
SPP
RNF
NMM
UAN
VNR
OCIP
CEQP
ARP
SDLP
NRP
LRE
LGCY
LINE
LNCO
EROC
BBEP
NSLP
MCEP
NKA
RNO
2014 MLP Price Returns
0% 25% 50% 75% 100%
PSXP
TEP
WGP
MPLX
EQM
OILT
TCP
SUN
EEQ
ETE
MMP
EMES
EEP
CAPL
SEP
OCIR
SRLP
NSH
TRGP
RRMS
CQH
KMI
VLP
WES
WMB
WNRL
SGU
ETP
NS
TLLP
ARLP
FISH
CQP
SXL
EPD
BPL
DKL
APU
2014 MLP Price Returns
-30% -20% -10% 0% 10%
SEMG
ENLK
WPT
SE
AHGP
GMLP
STON
MWE
SMLP
PAA
SXCP
TGP
ENLC
ACMP
FGP
DMLP
PAGP
FUN
GLP
SPH
NGLS
OKE
DPM
HEP
RGP
NTI
WPZ
ARCX
CLMT
NGL
HCLP
GEL
KNOP
OXF
TOO
SXE
APL
BKEP
2014 MLP Price Returns
Source: Bloomberg, USCA, as of 12/31/14
15
-50% -25% 0% 25% 50% 75% 100%
DM
SHLX
NEP
WLKP
VTTI
GLOP
CNNX
AM
HMLP
RMP
ENBL
PBFX
LMRK
FELP
USDP
NAP
CELP
RIGP
VNOM
JPEP
2014 MLP IPO Price Returns
Commodity Pricing Commentary
16
Source: Bloomberg, EIA, USCA
17
Biggest story of the year was collapse in NGL prices following the crude drop in Q4’14. NGL prices got an artificial boost in Q1 on cold weather and surging propane prices. But the propane shortage quickly turned into a glut – just like the rest of the NGL barrel. And NGLs took another major leg down with oil in October.
And the #2 story was ethane decoupling from methane beginning mid summer. Common view was that methane would provide a floor for ethane, as producers could keep ethane in the gas stream via ethane rejection, but recently ethane has traded to as low as 70% of its methane equivalent value.
So what happened?
• Gas production came in much higher than expected (+7% vs. our 2% assumption), and NGL yield finished in-line with expectations, up 7% to 1.6 GPM (ethane yield flat, C3+ yield up ~10%).
• Petchem industry looks to average 1,025 mbpd of cracking in ‘14, 2% below our forecasted 1,050 mbpd, with Geismar not coming online mid-year as expected (~55 mbpd when online)…
• …leaving 20 mbpd of excess ethane supply despite an estimated 350 mbpd of ethane rejection.
• Propane inventories, which began the year 15 mmbbls (28%) below the 5-yr avg. ended the year 21 mmbbls (35%) above the 5-year avg.
• And the heavier ends of the barrel (C4+) are down 47% since Oct. 1 with the 42% drop in crude oil prices.
Result was basically flat NGL prices for the year, but a 35% decline from average Q1 prices to average Q4 prices.
25%
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35%
40%
45%
50%
40
50
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100
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c/ga
l
Absolute and Relative Prices - C2+ Barrel
Absolute Price (c/gal) Relative Price (% of WTI)
$-
$2
$4
$6
$8
$10
$12
$14
Ethane and Natural Gas Prices ($/mmbtu)
Ethane Methane
18
Source: USCA, EIA
Table to the right shows historical ethane supply and demand functions as well as our ’15-’17 outlook.
Despite the first ethane exports from the US in over 25 years and a ~30 mbpd increase in ethane cracking, our estimate of ethane rejection ballooned to ~350 mbpd in ’14.
And despite additional exports coming online over the next two years, we see ethane rejection increasing to ~600 mbpd by 2016.
In 2017, US should have 4 world-scale crackers come online plus have a full year of EPD and Mariner East 2 ethane exports. Ethane rejection declines, but still remains significant at ~500 mbpd.
Given large amount of ethane rejection, we’re assuming that no matter the increase in ethane demand from cracker expansions/conversions and additional exports over the next three years, it will not be enough to move ethane prices above their methane equivalent.
Additionally, given the significant oversupply we expect additional export announcements to be made in ’15 (whether it’s EPD, NGLS, American Ethane or someone else.
For purposes of prognostication, we are estimating an increase of ~80 mbpd in ethane cracking during ’15, ~25 mbpd in ’16 and ~200 mbpd in ‘17, which should come from:
• WPZ’s Geismar facility and expansion is scheduled to come online in early Jan and should add ~55 mbpd.
• Minor expansions and conversion amongst existing crackers that we believe will lead to modest ethane cracking increases of ~25 mbpd annually.
• Four new world scale crackers that should come online over the course of 2017 (~90 mbpd of ethane consumption each) which equates to two additional crackers on average over the year.
USCA Ethane Supply/Demand Scenario
Year Ending December 2011A 2012A 2013A 2014A 2015E 2016E 2017E
Supply (mbbl/d)
Potential Production 945 1,067 1,187 1,427 1,603 1,718 1,842
Est Ethane Rejection 0 (75) (210) (355) (403) (591) (498)
Total Net Production 945 992 977 1,072 1,200 1,127 1,344
Cracking Demand (mbbl/d) 949 958 990 1,021 1,100 1,125 1,325
Ethane Exports 0 0 0 32 100 175 455
Net (Draw)/Build (mbbl/d) (4) 34 (13) 19 2 2 19
Inventories (mbbls)
Beg of Year 24,323 22,892 35,396 30,818 37,902 38,500 39,375
Change in Inventory (1,431) 12,504 (4,578) 7,084 598 875 7,000
End of Year 22,892 35,396 30,818 37,902 38,500 39,375 46,375
Days of Supply 24 37 31 37 35 35 35
Our forecast of future ethane exports above assumes exports from the following facilities:
• SXL’s Mariner West Pipeline (50 mbpd) – Q1’14
• PBA’s Vantage Pipeline (40 mbpd) – Q2’14
• SXL’s Mariner East 1 and 2 (125 mbpd) – Q2’15, Q4’16
• EPD’s Gulf Coast Facility (240 mbpd) – Q3’16
19
Source: USCA, EIA
Table to the right shows historical propane supply and demand functions as well as our ’15-’17 outlook.
2014 saw a massive increase in propane production from gas plants (+137 mbpd, or 17% vs. ’13) as US gas production was up 5 Bcf/d (!), and producers continued to drill richer gas, growing propane’s GPM yield by 12%.
Despite an unseasonably cold winter and record low inventories in the early months of the year, the increase in propane production steadily pushed up inventories to the point where they are once again at record highs.
New export facilities should help soak up this excess near term as NGLS’ ~65 mbpd expansion came on in Q3’14, EPD will have a ~50 mbpd expansion on by Q1’15, by which time SXL should also have their ~200 mbpd facility up and running.
Longer term however, we wonder if there will be enough propane supply to keep export facilities operating at high utilizations.
Assuming new PDH plants get their fill of propane first, by 2017, we estimate that there will only be ~625 mbpd of propane available for export with ~1,250 mbpd of export capacity.
• Some of that excess capacity can be soaked up by butane exports, but we get that there will only be ~200 mbpd of excess butane in ’17.
• In order to fill remaining capacity, we would need to see significant gas production growth that, in our view, cannot be supported with current commodity prices.
USCA Propane Supply/Demand Scenario
Year Ending October 2011A 2012A 2013A 2014A 2015E 2016E 2017E
Supply (mbbl/d)
Gas Plant Production 618 695 800 937 1,075 1,153 1,236
Refinery Production 551 553 562 581 580 580 580
Total Production 1,169 1,248 1,362 1,518 1,655 1,733 1,816
Demand (mbbl/d)
Domestic Use 1,166 1,168 1,259 1,170 1,200 1,200 1,200
New PDH Facilities 10 45 80
Gulf Coast Exports (and Mariner East) 112 140 252 379 550 600 625
Other Exports 13 15 18 32 20 20 20
Imports (117) (112) (126) (116) (110) (110) (110)
Other (Balancing Element) 0 (4) (8) 1 0 0 0
Total Demand 1,174 1,207 1,395 1,466 1,670 1,755 1,815
Net (Draw)/Build (mbbl/d) (5) 41 (33) 52 (15) (22) 1
Inventories (mbbls)
Beg of Year (October) 61,412 59,720 74,639 62,526 81,409 75,934 67,904
Change in Inventory (1,692) 14,919 (12,113) 18,883 (5,475) (8,030) 365
End of Year (October) 59,720 74,639 62,526 81,409 75,934 67,904 68,269
Our 2017 export capacity estimate of ~1,250 mbpd consists only of projects we view as highly likely and does not include more speculative projects. Included in our estimate of capacity by 2017 are:
• EPD – 533 mbpd
• NGLS – 200 mbpd
• SXL – 367 mbpd (Mariner South and Mariner East)
• PSX – 150 mbpd
NGL Data Points (October ‘14 data)
Source: EIA, USCA
20
500
600
700
800
900
1,000
1,100
1,200
Eth
ane
Pro
du
ctio
n (m
bb
l/d
)
U.S. Monthly Ethane Production (mbbl/d)
5-Year Range 2013 5-Year Avg 2014
400
500
600
700
800
900
1,000
1,100
Pro
pan
e Pr
od
uct
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bl/
d)
U.S. Monthly Propane Production (mbbl/d)
5-Year Range 2013 5-Year Avg 2014
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
Eth
ane
In
ven
tori
es
(mb
bls
)
U.S. Ethane/Ethylene Balances (mbbls)
5 Year Range 2013 2014 5 Year Avg
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
Eth
ane
In
ven
tori
es
(mb
bls
)
U.S. Propane/Propylene Balances (mbbls)
5 Year Range 2013 2014 5 Year Avg
21
Despite the composite NGL barrel trading at its lowest levels since 2002 (currently 40c/gal – even in Dec ’08 with crude at $40/bbl NGLs traded only as low as 45c/gal), we are modestly bullish on NGL prices. While we see little upside to ethane, propane exports and a modest increase in crude prices should provide some relief:
• Ethane: Still capped at maximum of methane prices. At our $3.25/mcf gas price assumption, that’s 21c/gal. We think ethane will trade below that given the incentive to realize higher propane prices and limits on ethane rejection due to gas pipeline BTU limitations.
• Propane: Export facilities provide near term uplift. With propane inventories at all-time highs and ~20 mmbbls over 5-year averages, the addition of SXL’s Mariner East and Mariner South and EPD’s Gulf Coast Expansion in early ’15 should provide an additional ~300 mbpd of export capacity to soak up a flooded local market.
• C4+: Higher crude price forecast should provide tailwind. Exacerbating the NGL barrel decline has been that in addition to lower crude prices, butanes and pentanes have also been trading lower on a relative basis – butanes now at 53% of crude and pentane at 78% vs. 2014 averages of 55% and 89%. Assuming the heavier portion of the barrel returns to historical trading averages on a relative basis and we see crude improve to ~$60/bbl in ’15, we should see some improvement in C4+ pricing.
For ‘15, we are assuming that NGLs trade at ~38.5% of crude oil or ~55c/gal, about 35% above their current prices.
Stellar start, dismal finish is the best way to describe ’14, with weather the driver of both (1Q 10% colder than normal and 4Q 6% warmer than normal).
Storage swung from being 55% below the 5-year average at the first of April to basically normal by the end of the year. Those massive injections helped support gas prices, until there was no more room left at the inn.
Total production rose a whopping ~7% or 5 bcf/d, with some of the bigger gainers looking like this:
• Marcellus production +3.7 bcf/d, to 14.9 bcf/d;
• Utica production, while adding only 0.8 bcf/d, took off from a starting level of 0.2 bcf/d in Jan. ‘13 to an estimated 1.7 bcf/d in Dec. ’14;
• Eagle Ford production +1.4 bcf/d, to 6.6 bcf/d;
• And Haynesville production -0.9 bcf/d to 6.8 bcf/d.
Source: EIA, Bloomberg, USCA
22
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
Weekly Natural Gas Storage Levels (Bcf)
7 Year Range 5 Year Average 2013 2014
$0
$2
$4
$6
$8
Henry Hub Spot Gas Price ($/mmbtu)
5 Year Range 5 Year Average 2014 2013
45
50
55
60
65
70
75
80
85
2014 U.S. Gas Production (Bcf/d)
$50
$60
$70
$80
$90
$100
$110
$120
$(25)
$(20)
$(15)
$(10)
$(5)
$-
$5
$10
$15
Pro
mp
t M
on
th C
rud
e P
rice
($/
bb
l)
Spre
ad t
o P
rom
pt
Mo
nth
($/
bb
l)
Crude Oil Term Structure (WTI, $/bbl) 2nd Month vs Prompt 6th Month vs Prompt 12th Month vs Prompt
24th Month vs Prompt Prompt Month Price
11.5
10.8
10.0
4.23.9
46.3
Worldwide Crude Production (mmbbl/d)
Saudi Arabia
Russia
USA
China
Canada
Rest of World
Year-end Collapse: While ‘14 crude oil prices averaged $93/bbl, down only 5% from ‘13, prices have been in a freefall since early October to now sub $50/bbl.
Contango Market: Current forward NYMEX strips look like this: ’15 - $52/bbl, ‘16 - $58 and ‘17 - $62. A dramatic change from a year ago at this time when the strips were $89, $84 and $81, respectively. And the market moved from backwardated to contango in early October.
Continued Domestic Oil Growth: U.S. oil production rose another 1.2 mbpd in ‘14, following a 1 mmbpd increase in ‘13. U.S. oil production reached its highest level in almost 30 years (Feb ’86) and now consistently produces more crude than it imports.
Permian Revival: A revival has been under way for a couple of years in the Permian, but accelerated in ‘14 as rigs transitioned to horizontal dominated. Permian production grew ~400 mbpd. For the Eagle Ford and Bakken, the pace of production growth was steady, +260 and +450 mbpd, respectively.
Game of Chicken: Following a surge of production online in the last 6 months (U.S. +500 mbpd and Libya +200 mbpd, plus others), OPEC (Saudi) has dug in their heels and decided to see how much pain other countries can take before they start cutting investment and/or curtailing production. At sub-$60 oil, the pain is acute, and we are already seeing some drastic capex cuts out of the more-levered E&Ps.
23
Source: EIA, Bloomberg, BP Statistical Review of World Energy 2013, USCA
-
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
Crude Production by Region (mbbl/d)
Bakken Eagle Ford Niobrara Permian
USCA Price Deck: Our commodity price assumptions along 12-month strip pricing (as of 1.7.15) are shown below. Our view is shaped by the following:
Source: USCA, Bloomberg (strip as of 1.7.15)
• Oil: The pain OPEC (basically Saudi) is inflicting to curb the shale revolution and weaken Russia and Iran in particular is also straining OPEC country budgets (most budgets need >$90 oil). Yes, Saudi has $750B or two years of reserves, but we think there is a limit to how long they’ll let this last. If the deficits start to impact social programs, the risk of political instability rises materially. For the first time in an oil cycle, the primary marginal supplier of oil (U.S.) has a very steep decline curve (things will correct quicker). And, not much in the world is truly economic sub $60/bbl.
• NGLs: While we see an oversupply of ethane lasting at least several years, we think the additional ~250 mbpd of propane export capacity in Q1’15 and another ~230 mbpd by Q4’15 will place upward pressure on propane prices.
• Gas: We are not too much above the current ‘15 gas strip of $2.98/mcf. At ~$3 gas in January, we think curtailments are likely, the pace of supply growth is likely to slow as rigs are dropped, and low prices should further stimulate demand. For the year, although we have gas production growing by 4 bcf/d or +5%, we have the year over year rate of change slowing to 1% by March.
Producer Behavior is Cash-Flow Driven: It’s not about the break-even price of a play, it’s about how much cash does a producer can spend without incurring excessive leverage. As such, our E&P team put out a great analysis of rigs at risk of being dropped due to excess producer leverage. We are including it on the next few pages, first the big picture and then basin drill downs, as it’s been a pretty good predictor so far of company announcements. Following that, we tabulate E&P capex cuts to date.
24
Gas ($/mcf) Oil ($/bbl) NGLs ($/gal) Gas ($/mcf) Oil ($/bbl) NGLs ($/gal)
USCA Assumptions $3.25 $60 $0.55 $3.75 $75 $0.65
12-month strip $2.98 $52 $0.42 $3.35 $58 $0.45
2015 2016
25
Source: Drilling Info., USCA
Our E&P team put this together early on in the oil price collapse and then refreshed it this week. It has proved so far to be a very good indicator of rigs at risk of being dropped as operators become strapped for cash. Note this only represents rigs for publicly traded companies.
The color continuum represents the leverage profile of the E&P operator using consensus net debt to ’15 EBITDA, with green being relatively lower leverage and red being higher leverage. Cut off for starting to color a rig red/higher risk was 2.5x net debt to ’15 EBITDA. In addition to current debt, they layered on additional debt in ‘15 corresponding to the amount of cash flow outspend.
26
Source: Drilling Info., USCA
Operator Leverage Rigs
EOX 4.6x 4
TPLM 3.9x 4
OAS 3.1x 17
QEP 2.5x 7
CLR 2.0x 20
NFX 2.0x 4
WLL 1.7x 17
SM 1.7x 6
EOG 0.7x 6
OXY 0.3x 6
DNR 0.0x 1
Bakken
27
Source: Drilling Info., USCA
Operator Leverage Rigs
SD 4.1x 34
MPO 3.9x 7
PQ 3.0x 2
RRC 2.7x 2
CHK 2.6x 21
GST 2.6x 1
UNT 2.1x 7
CLR 2.0x 26
NFX 2.0x 11
APA 1.6x 11
XEC 1.3x 6
DVN 1.1x 7
EOG 0.7x 2
MidCon
28
Source: Drilling Info., USCA
Operator Leverage Rigs
HK 4.7x 4
CRK 4.4x 3
XCO 4.4x 3
SFY 4.1x 2
ROSE 3.7x 2
EPE 2.8x 5
CHK 2.6x 20
CRZO 2.6x 4
PVA 2.5x 7
SM 1.7x 4
APA 1.6x 12
PXD 1.2x 6
DVN 1.1x 3
APC 0.9x 8
COG 0.9x 4
EOG 0.7x 24
Eagle Ford
29
Source: Drilling Info., USCA
Operator Leverage Rigs
REN 5.7x 1
ROSE 3.7x 5
LPI 3.3x 8
EPE 2.8x 4
WTI 2.7x 3
CHK 2.6x 1
RSPP 2.5x 7
QEP 2.5x 5
EQT 2.4x 1
AREX 2.3x 3
PE 2.2x 5
CXO 2.1x 36
SM 1.7x 1
WLL 1.7x 1
APA 1.6x 34
FANG 1.5x 5
XEC 1.3x 17
EGN 1.3x 13
PXD 1.2x 27
DVN 1.1x 19
APC 0.9x 10
EOG 0.7x 8
OXY 0.3x 32
Permian
30
Source: Drilling Info., USCA
Operator Leverage Rigs
REXX 3.9x 3
AR 3.7x 14
RICE 3.6x 4
RRC 2.7x 9
CHK 2.6x 12
CRZO 2.6x 1
GST 2.6x 1
EQT 2.4x 11
SGY 2.4x 1
AREX 2.3x 2
SWN 2.1x 3
ECR 2.1x 2
GPOR 1.9x 6
NBL 1.5x 6
COG 0.9x 6
APC 0.9x 1
Appalachia
31
Source: Company reports, USCA
Above we tabulate the handful of capex cuts to date. So far, a 41% drop in planned rig count for ‘15 vs. ‘14, but production is till projected to grow by 11%.
Expect a lot more over the next two months as companies roll out ‘15 plans with Q4 earnings. And we will continue to update this as the cuts roll in.
Ticker Basin'14
Estimate
'15
Guidance
%
Change'14 '15
%
Change
'14
Consensus
'15
Guidance
%
ChangeEstimated Midstream Provider(s)
SN Eagle Ford $870 $625 -28% 8 4 -50% 16.6 17.6 6% KMI, EPD, RGP, DPM, ETP, ENLK
MTDR Permian/Eagle Ford $570 $350 -39% 5 3 -40% 8.0 4.0 -50% DCP Midstream, NGLS
CXO Permian $2,600 $2,000 -23% 36 26 -28% 71.4 72.5 2% DCP Midstream, NGLS
BBEP Permian/Mid-Con $375 $200 -47% na na na 22.0 31.1 41% West Texas Gas (private)
LINE California/Green River/E. TX $1,550 $730 -53% na na na 72.7 62.5 -14% WPZ, EPD, TLLP
AMZG Bakken $115 $5 -96% 1 0 -100% 2.1 na na
CLR Bakken / SCOOP $4,550 $2,700 -41% 50 31 -38% 121.1 142.9 18% OKS, DCP Midstream LLC, APL, ENBL
REXX Marcellus/Utica $358 $200 -44% 3 na na na na na MWE
CRK Eagle Ford/TMS/Haynesville $580 $307 -47% 5 2 -60% 11.9 10.1 -15% EPD, PAA, KMI, MMP, RGP, SXE
MRO Global $5,500 $4,400 -20% na na na na na na
ROSE Permian / Eagle Ford $1,200 $750 -38% 7 4 -43% 19.4 21.3 10% RGP, ETP, KMI, PAA
AREX Permian $400 $180 -55% 3 1 -67% 5.5 5.7 4%
LPI Permian $1,100 $525 -52% 14 5 -64% 18.3 20.5 12% APL, NGLS, ENLK, DCP Midstream LLC
ECA** Eagle Ford/Permian $2,550 $2,800 10% 36 25.75 -28% 118.6 150.0 26% ETP, EPD, DCP Midstream LLC
AXAS TMS $190 $54 -72% na 1 na 4.2 6.4 53%
EOX Bakken $250 $72 -71% 3 1 -67% 3.4 4.4 30% OKS
Chaparral* Mid-Con $671 $336 -50% 10 5 -50% 17.4 17.4 0% APL, DCP Midstream LLC
OAS Bakken $1,425 $800 -44% 16 6 -63% 40.1 43.1 8% Oasis Midstream
GDP TMS $350 $175 -50% 4 2 -50% 4.7 6.4 36%
PDCE Niobrara/Utica $637 $557 -13% 6 5 -17% 12.8 17.4 36% DPM
COP Global $16,875 $13,500 -20% na na na na na na
Total - $42,716 $31,265 -27% 207 122 -41% 570.1 633.4 11%
*Indicates Company Guidance and numbers are BOE (including natural gas)
**2014 consensus adjusted upwards to gross up for full year of ATHL and FCA acquisitions
Capex ($mm) Rig Count Oil Production (mboepd)
Infrastructure Build
32
Project Announcements By Project Type
Project Type Cost ($mm)
Gas pipeline $35,825
Crude oil pipeline 13,200
Gas processing 5,900
NGL pipeline 4,650
LPG exports 2,640
Fractionator 2,505
Refined products pipeline 1,150
Condensate 1,015
Crude logistics 730
Grand Total $67,615
The Numbers – Below is a quick summary of the significant announcements we have tracked throughout 2014, with several caveats. These only reflect announcements from publicly traded companies for U.S. infrastructure projects >$100mm, where we can reasonably estimate costs (if not otherwise given) and where the project has a good likelihood of proceeding. In all, we tally 85 projects totaling almost $70B announced during ’14 – a pretty staggering number.
• Gas Pipelines Dominate…: More on that over the next few pages, but gas pipelines dominated the announcements, accounting for 53% of the potential capex spend.
• …So Goes Appalachia: The bulk of the gas pipeline spend is to alleviate Appalachia bottlenecks, so that basin takes the lion’s share of future capex.
What’s Not Here – Noticeably absent are a couple of projects which did not happen in 2014. Both the proposed raw NGL pipelines from Appalachia to the Gulf Coast failed to launch, and instead were replaced by SXL’s planned $2.5B Mariner East pipeline to the east coast. Not terribly surprising, but Keystone XL again failed to obtain regulatory approvals needed to move forward.
Source: USCA, Company reports
33
Project Announcements By Basin
Basin Cost ($mm) Basin Cost ($mm)
Appalachia $33,885 To Mexico 940
Demand Centers 8,450 Utica 750
Bakken 6,480 LNG 700
Gulf Coast 4,940 SCOOP 620
DJ Basin 4,530 Eagle Ford 600
Permian 3,960 W. Coast 500
ArkLaTex 1,260
Grand Total $67,615
2014 was the year when we hit the tipping point, where NE supply exceeded demand on an average daily basis – and boy did it ever show up in basis differentials.
Over the past 24 months, Appalachia production has grown by 8.5 bcf/d, overwhelming a pipeline system designed for entirely different flows.
Pipelines had been cautioning that this would happen and that they needed several years of lead time along with firm contract commitments in order to ensure adequate take away capacity. But few producers were willing to make those long-term commitments.
Everything changed with this winter’s basis blowout. Producers had pen in hand, willing to sign up for whatever was available, and pipelines scrambled to accommodate them announcing project after project to reverse flow to the west and south. The next wave, still under the contracting phase, are NE demand-driven projects to serve incremental NE load.
34
Source: EIA, Bloomberg, USCA
-
5
10
15
20
25
NE Natural Gas Supply and Demand (Bcf/d) Total NE Demand
Total NE Demand - TTM Average
Marcellus/Utica Production
$(6.00)
$(5.00)
$(4.00)
$(3.00)
$(2.00)
$(1.00)
$-
$1.00
$2.00
Appalachia Gas Pricing Basis to Henry Hub ($/mmbtu)
Columbia Gas - Appalachia Leidy Hub
Dominion South TGP Zone 4
Tables to the left detail pipeline projects to take gas out of SW and NE Appalachia, including projects which came online during ‘14. Note that these include only those projects that originate within and terminate outside production areas.
When we published our Appalachia infrastructure piece in late April ’14, projects to move gas out of SW PA totaled ~15 bcf/d with ~$8B of investment. In the course of four months, that number ballooned to projects totaling ~28 bcf/d with ~$36B of investment.
Note that we are just now really entering the major build cycle for these projects as 77% are scheduled to come online post 2015.
As is frequently the case in infrastructure, we think it’s very likely that the region becomes overpiped.
35
NE Marcellus Added Takeaway
Company Project Name Pipeline Cost ($mm)Capacity
(mmcf/d)
In-
Service
Firm/
Proposed
WPZ NE Connector Transco $50 100 Nov. '14 Firm
NI East Side Expansion Columbia Gas $275 310 Q3'15 Firm
NFG Northern Access 2015 NFG Supply $67 140 Nov '15 Firm
WPZ Leidy Southeast Transco $600 525 Late '15 Firm
WPZ/COG/PNY/WGL Constitution Pipeline Constitution Pipeline $740 650 Q1'16 Firm
NFG Northern Access 2016 NFG Supply $360 350 Late '16 Firm
WPZ Atlantic Sunrise Transco $2,100 1,700 2H'17 Firm
GAS/NJR/SJI/UGI/SEP PennEast Pipeline PennEast Pipeline $1,000 1,000 Q4'17 Firm
WPZ Diamond East Transco $650 1,000 Q3'18 Proposed
Total $5,842 5,775
Source: Company reports, USCA
SW Marcellus/Utica Added Takeaway
Company Project Name Pipeline Cost ($mm)Capacity
(mmcf/d)
In-
Service
Firm/
Proposed
KMP Utica Backhaul Tennessee Gas $160 500 Apr '14 Firm
TEP GP Seneca Lateral Phase I Rockies Express $100 250 Jun '14 Firm
NI West Side Expansion Columbia Gas & Columbia Gulf $200 540 Nov '14 Firm
SEP TEAM-South Texas Eastern $50 300 Nov '14 Firm
SEP TEAM 2014 Texas Eastern $500 600 2H'14 Firm
TEP GP Seneca Lateral Phase II Rockies Express $100 350 Q4'14 Firm
TEP GP REX Reversal Phase I Rockies Express $500 1,200 2015 Firm
SEP Uniontown to Gas City Texas Eastern $60 425 Nov '15 Firm
KMP Broad Run Flexibility Tennessee Gas $590 590 Nov '15 Firm
SEP OPEN Texas Eastern $500 550 Q4'15 Firm
TEP GP REX Reversal Phase II* Rockies Express $2,000 1,200 '16-'17 Proposed
SEP Gulf Markets Expansion Texas Eastern $150 650 Nov '16 Firm
NI Leach Xpress Columbia Gas $1,420 1,000 Nov '16 Firm
NI Utica Access Columbia Gas $50 200 Q4'16 Firm
ETP ET Rover ET Rover $4,100 3,250 Q4'16 Firm
DTE/ENB/SEP NEXUS Gas Transmission NEXUS Gas Transmission $3,000 2,000 2017 Firm
TRP ANR East ANR Pipeline $3,000 1,200 Q3'17 Proposed
SEP Access South Texas Eastern $200 250 H2'17 Firm
SEP Adair Southwest Texas Eastern $200 250 H2'17 Firm
KMP Broad Run Expansion Tennessee Gas $200 200 Nov '17 Firm
EQT/EQM/NEE Mountain Valley Pipeline* Equitrans $3,500 2,000 Q4'18 Firm
NI WB Xpress* Columbia Gas $870 1,300 Q4'18 Firm
D/DUK/PNY/GAS Atlantic Coast Dominion $4,750 1,500 Q4'18 Firm
WPZ Western Marcellus* Transco $3,000 1,500 Q4'18 Proposed
NI Mountaineer Xpress* Columbia Gas $1,000 750 Q4'18 Proposed
Total $30,200 22,555
*Estimate as open season under way; actual amount could vary
Bold, italic represents USCA estimates of project cost
36
Source: DOE, Company reports, USCA
Biggest news on the LNG front this year was DOE’s decision to remove their “order-of-precedence” approval process.
Beginning in August ‘14, LNG export facilities were able to receive final DOE approval as soon as they have completed the more rigorous and time consuming FERC process.
Three facilities received final DOE approval to begin LNG exports in ‘14: Cameron, Cove Point, and Freeport and all have indicated that they have begun construction activities.
Biggest question on LNG going forward is no longer regulatory based, but rather economics based – with world-wide LNG generally priced as a percent of crude and crude prices sub $50/bbl, does anyone want to sign up for long-term capacity?
Major Proposed U.S. LNG Export Facilities
LNG Facility OwnershipPotential Export
Volumes (Bcf/d)Contracted?
Potential First
In-ServiceFERC Status
Sabine Pass (T1-4) CQP 2.8 Yes 2015 Approved
Cove Point D 0.8 Yes 2017 Approved
Southern LNG KMI/RDS 0.4 Yes 2017 Filed
Cameron SRE 1.7 Yes 2018 Approved
Freeport LNG COP (50%) 1.8 Yes 2018 Approved
Jordan Cove VSN 0.8 No 2018 Draft EIS
Corpus Christi (T1-2) LNG 1.3 Yes 2018 Final EIS
Golden Pass XOM/Qatar 2.2 Yes 2018 Filed
Sabine Pass (T5) CQP 0.6 Yes 2018 Final EIS
Magnolia LNG LNG.AU/Stonepeak 1.1 No 2018 Filed
Lake Charles LNG ETE/BG 2.0 Yes 2019 Filed
Sabine Pass (T6) CQP 0.6 No 2019 Final EIS
Corpus Christi (T3) LNG 0.7 Partial 2019 Final EIS
Gulf LNG KMI (50%)/GE (46%) 1.5 No 2019 Pre-Filed
Oregon LNG Private 1.3 No 2019 Filed
Excelerate Energy Private 1.4 No na Filed / Rescinded
Total/Contracted Total 20.8 13.5
TX
AZ NM OK
Waha Hub
Agua Dulce Hub
Mexico
Edinburg
Tucson
Company: KMI Capacity: 200 mmcf/d In-Service: Nov ‘14
Company: NET Midstream Capacity: 2.1 Bcf/d In-Service: Dec ‘14
Company: ETP Capacity: 130 mmcf/d In-Service: Dec ‘14
Company: KMI Capacity: 500 mmcf/d In-Service: Jan ‘15
Company: OKS Capacity: ~550 mmcf/d In-Service: n/a
Company: TBD* Capacity: 1.4 Bcf/d In-Service: March ‘17 Company: TBD*
Capacity: 1.5 Bcf/d In-Service: Jan ‘17
* Project to be awarded by CFE during Q1’15.
Perhaps lost in the frenzy of midstream activity has been a quiet but steady increase in U.S. gas exports to Mexico. Volumes are now running ~2.2 bcf/d, up from ~1 bcf/d at beginning of 2011.
Beyond the current volumes, a significant amount of infrastructure is being built to increase export capacity to Mexico by at least 5.8 bcf/d by ’17. Adding in OKS’ open season under way for 500-600 mmcf/d could take that total to ~6.4 bcf/d.
Included in that total are three projects with total capacity of ~2.4 bcf/d that came online in Q4’14, plus another 500 mmcf/d project that is scheduled to come online this month.
Also included are two U.S.-to-Mexico gas pipeline projects with total capacity of ~2.8 bcf/d (’17 in-service) which the CFE is scheduled to award over the next couple of months.
37
Source: EIA, Company reports, USCA
0
500
1,000
1,500
2,000
2,500
U.S. Gas Exports to Mexico (mmcf/d)
Plenty of Backlog: Midstream backlogs are chock full following the burst of activity in 2014. This is a year to digest and execute, particularly as we enter a major gas pipeline build cycle.
Deferrals Likely: Producer capex cuts have just now begun to trickle in, and E&Ps are only talking about ‘15 volumes right now, which are driven primarily by drilling that occurred in ‘14. The elephant in the room is what happens to ‘16 volumes following some meaningful drilling slowdowns in ‘15. For the Midstream guys, the ball is in the E&P’s court, and they just have to wait for their next move. We think Midstream companies are doing some serious scrubbing of capex budgets – how many fewer well connects, which projects can and need to be deferred, and how do they work with their E&P customers to help ease the pain?
Bright Spots: Four bright spots in an otherwise nasty commodity tape are:
• Potential for much needed additional ethane export facilities;
• Likelihood of crude oil exports in ‘15 and the associated needed infrastructure;
• Preliminary discussion of another major round of new ethylene crackers on the drawing boards for the end of this decade; and
• With gas prices at $3, higher gas demand and potential market-pull gas pipeline projects.
38
Midstream M&A
39
Source: Company reports, USCA
Table to right highlights some of the more notable midstream M&A during ‘14 and categorizes some of the themes.
Record year of M&A by a longshot, with $185B of transactions. Two deals dominate the numbers: KMI’s $70B buy in of KMP, KMR and EPB, and the $37B WPZ/ACMP merger. Excluding those two mega deals, it was still a record year.
‘14 saw announcements to take out 9 publicly traded MLPs, up from 4 in ‘13.
For the first time in a while, M&A for individual assets was more active than for dropdowns.
Most interesting deals by far were Kinder buy in of KMP, EPB and KMR and Targa buyout of APL and ATLS – with both GPs capturing the LP depreciation tax shield.
40
Acquirer Seller Asset Value($mm)
Public Company Acquisitions
KMI KMP, EPB and KMR Entire Company $70,000
ACMP WPZ Entire Company $37,000
TRGP/NGLS APL and ATLS LP and GP interests in APL $7,700
EPD OILT LP and GP interests in OILT $6,038
BBEP QRE Entire Company $3,000
Koch Industries PDH Entire Company $2,100
ETP SUSS Entire Company $1,800
Asset Acquisitions
WMB GIP II 50% interest in ACMP GP and 55mm ACMP LP units $6,000
MPC HES Retail gasoline network $2,874
TLLP QEP QEP Field Services $2,500
LINN DVN 900k net acres in Rockies, Mid-Con, E. & S. TX and N. LA $2,300
Enervest LINN Position in Granite Wash and Cleveland plays $1,950
WES Nuevo Energy Permian gas plant and gathering $1,500
VSN GIP II 50% stake in Ruby Pipeline $1,430
PAA OXY 50% interest in BridgeTex Pipeline $1,075
MEMP Undisclosed Producing oil fields in WY $935
BPL Trafigura AG Corpus Christi complex and Eagle Ford gathering $860
GIP Hastings Funds 25% stake in Freeport LNG $850
OKS CVX 80% of W. TX LPG and 100% of Mesquite Pipelines $800
Major Dropdowns/Intracompany Sales
ETE ETP 40% interest in SXL IDRs $3,750
EPB KMI 50% of Gulf LNG and Ruby, 47.5% of Young Storage $2,000
ENF ENB Natural gas and diluent pipeline interests $1,760
WPZ WMB WMB Canadian Assets $1,200
DPM DCP Midstream 1/3 of Sand Hills & Southern Hills, Eagle Ford Assets, DJ Plant $1,150
EQM EQT Jupiter Gathering system $1,121
EEP ENB 66.7% interest in Alberta Clipper $1,000
Significant 2014 Midstream Energy Deals
Another Big Year Ahead – While we don’t think we beat the record $185B of M&A in ’14, we do think ‘15 will be another big year, with four key dynamics at play:
• Low Commodity Prices: Instead of the “rising tide lifts all boats” environment we had been in until recently, this much lower commodity price environment has really bifurcated yields. A year ago at this time, only 6 of the stocks were yielding >10%. Now, almost a third are pushing or >10% yields (8 are >20%), while another one third are sub 5%. That’s where opportunities are made.
• The Big Guys are Doing It: Kinder and Energy Transfer have put their stakes in the ground, and we don’t think they will disappoint in ’15. PAA has been predicting this pullback for couple of years and is poised to pounce on some opportunities.
• Asset Grab Under Way: We are now in the 9th year of the U.S. infrastructure boom. Backlogs are still robust, but the big shale plays have been found. So we see strategic buying in order to access specific basins and/or shore up positions in existing basins.
• Fragmented Sector: At year end, there were 134 MLPs and pure GPs, up from 60 in ’06, with a current collective market cap of almost $650B, up from $110B in ‘06. With so many IPOs over the last ten years, the space is dominated by primarily illiquid small-caps. Of the 134 names, only 18 (13%) have a market caps >$10B. One-third of the stocks have sub $1B market caps, and two-thirds sub $3B. That’s a space ripe for consolidation.
41
Capital Markets
42
Midstream Capital Markets – Action Continues
43
Amazing statistics for Midstream capital markets continued in 2014 (see next few pages for charts):
• Most notable was that ‘14 saw the most capital markets activity ever, with $78B of debt and equity issued versus $68B in ‘13 and $66B in ‘12.
• IPO activity remained high, although slightly lower than the record ’13. In ‘14, $7.7B was raised through 20 IPOs versus $8.5B in ’13 (21 IPOs). SHLX and AM led the charge with $1.1B and $1.2B raised, respectively, the largest MLP IPOs to date.
• Total of $38B in equity raised in ‘14 through follow-ons, private placements, IPOs and ATM programs (ATMs through Q3’14). Excluding ATM programs, there were 88 equity offerings in ‘14 with an average deal size of $370mm.
• ATM programs continued to pick up steam with $5.6B raised through Q3’14, almost topping the $5.9B raised in all of ’13. There are currently $16B of ATM program authorized for 36 companies, which compares with $11B and 29 companies at the end of ‘13. This includes KMI’s recently announced $5B ATM program.
• Debt markets remained hot with $40B of debt issued in ‘14 compared with $34B in ‘13.
• MLP industry (including pure GPs) closed ‘14 with 134 publicly traded companies with market cap of $633B. That’s up from 120 companies last year with a market cap of $590B and 36 companies ten years ago with market cap of $55B.
More to come:
• Currently 15 S-1s pending for new MLPs, three times as many than this time last year, and another five companies have publicly announced plans for additional MLP IPOs.
• We are unsure when, if ever, the IRS will formally end their “pause”. And we are not sure if it really matters as they have begun PLRs for mainstream MLP assets, and the pause has done little to dampen a high level of activity in the space.
Investor appetite for sector, strong for year, but fading at year end:
• Market cap of MLP and partial MLP products (OEFs, CEFs, ETFs and ETNs) grew 35% in ’14, to $75B.
• Industry funded 8 new products in ‘14. With most closed-end funds trading at a discount to NAV, it could be more difficult to raise money in the space for those types of funds.
MLP Money Flows – Steep End of Year Decline
Source: Bloomberg, USCA
44
Record year… 2014 saw a record $21B raised for the space through closed-end funds, open-end funds, ETFs and ETNs.
… but the year ended in a whimper, with only $521mm raised in the month, the lowest amount since December 2012.
Open-end funds dominated, accounting for 62% of the funds raised, or $12.8B. And closed-end funds faded, with only $3.1B raised compared with $4.9B in ‘13 and $3.4B each in ‘12 and ‘11.
MLP Initial Public Offering Activity
Source: Bloomberg, Company Reports, USCA
45
MLP Legend Midstream
GP
Upstream
Shipping
Coal
Propane
Other
Potential MLP IPOs
Company Industry Company Industry
Maxum Energy Logistics Refined Products Enviva Partners Other
PES Logistics Partners Other Terryville Mineral & Royalty Partners E&P
Hess Midstream Partners G&P Azure Midstream Partners G&P
Mammoth Energy Partners Oilfield Services Smart Sand Partners Oilfield Services
Exmar Energy Partners Other Sol-Wind Renewable Power Other
Columbia Pipeline Partners Natural Gas ET LNG MLP Other
PennTex Midstream Partners G&P Eureka Hunter MLP G&P
Coastamare Partners Shipping Noble Corp MLP Oilfield Services
Ocean Rig Partners Oilfield Services Consol Energy MLP Coal
Midcon Midstream Oilfield Services EQT MLP GP
MLP Capital Markets
Source: Company Reports, USCA
46
0
20
40
60
80
100
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
# o
f O
ffe
rin
gs
$m
m
Equity Offerings - All Offerings
Amount ($mm) Number of Offerings
0
10
20
30
40
50
60
70
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
# o
f O
ffe
rin
gs
$m
m
Debt Financings
Amount ($mm) Number of Offerings
0
5
10
15
20
25
30
35
0
500
1,000
1,500
2,000
2,500
Q1'12 Q2'12 Q3'12 Q4'12 Q1'13 Q2'13 Q3'13 Q4'13 Q1'14 Q2'14 Q3'14
# o
f Is
sue
rs
$m
m
ATM Equity Offerings
Amount ($mm) Number of Issuers
0
5
10
15
20
25
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
# o
f IP
Os
$m
m
Equity Offerings - IPOs
Amount ($mm) Number of Offerings
ATM Programs Replacing Overnight Deals
Source: Company Reports, USCA
47
MLP ATM Programs ($mm)
TickerCurrent ATM
Program Amount
Issuances
2009-2012
Issuances
2013Q1'14 ytd Q2'14 ytd Q3'14 ytd
Total Remaining
on ATM Program
ACMP $300 $0 $50 $8 $52 $52 $198
APL $250 $9 $138 $0 $47 $122 $128
ARP $100 $0 $0 $0 $0 $0 $100
BPL $300 $0 $33 $52 $75 $75 $226
BWP $500 $0 $0 $0 $0 $0 $500
CLMT $300 $0 $0 $0 $0 $4 $296
CQP $500 $11 $0 $0 $0 $0 $500
DPM $500 $79 $154 $0 $110 $248 $458
EEP $500 $155 $0 $0 $0 $0 $469
ENLK $300 $0 $0 $0 $20 $72 $300
EPB $500 $0 $87 $36 $77 $152 $336
EPD $1,250 $205 $460 $0 $58 $58 $1,192
EROC $100 $7 $6 $0 $0 $0 $87
ETP $1,000 $200 $846 $106 $417 $1,030 $109
KMI $5,000 $0 $0 $0 $0 $0 $5,000
KMP $1,900 $1,529 $900 $16 $335 $441 $1,008
KMR $500 $0 $210 $6 $97 $134 $156
LGCY $60 $2 $0 $0 $0 $0 $58
LINE $411 $87 $0 $0 $0 $0 $411
LRE $75 $0 $0 $4 $15 $23 $52
MMLP $300 $0 $0 $5 $17 $21 $279
MWE $1,200 $6 $1,698 $272 $712 $1,054 $418
NGLS $400 $0 $518 $163 $163 $257 $311
NKA $75 $0 $0 $0 $0 $0 $75
NRP $75 $0 $0 $6 $17 $25 $50
NS $200 $6 $0 $0 $0 $0 $194
NSLP $50 $0 $0 $0 $0 $50
OKS $300 $0 $36 $57 $164 $245 $19
PAA $900 $524 $477 $151 $453 $669 $231
RGP $400 $15 $149 $34 $65 $162 $272
SEP $400 $0 $24 $52 $191 $283 $93
SXCP $75 $0 $0 $0 $0 $2 $73
SXL $1,250 $0 $0 $0 $102 $231 $1,019
TCP $200 $0 $0 $0 $0 $73 $127
TLLP $200 $0 $0 $0 $0 $14 $186
VNR $500 $12 $53 $35 $100 $148 $331
WPZ $600 $0 $0 $0 $0 $55 $545
Total $21,696 $2,848 $5,932 $1,002 $3,288 $5,649 $16,007
By Quarter $1,002 $2,286 $2,361
MLP Universe Continues to Expand Total MLP Universe:
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
No of MLPs 31 32 36 47 60 74 77 70 74 84 101 120 134
Total Mkt Cap ($B) $30 $47 $55 $71 $109 $145 $90 $159 $220 $308 $422 $590 $633
Mkt Cap Growth 11% 57% 17% 29% 54% 33% -38% 77% 38% 40% 37% 46% 7%
MLP Products (CEFs, OEFs, ETFs, ETNs) Also Growing:
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
No of MLP Products 4 7 8 11 11 13 27 40 47 59 70
Total Mkt Cap ($B) $1.7 $2.9 $4.0 $4.5 $2.4 $5.2 $13.6 $21.2 $30.7 $55.9 $75.2
Mkt Cap Growth 74% 39% 13% -48% 120% 162% 55% 45% 82% 35%
Source: Bloomberg, USCA
48
Midstream Equity Needs in 2015
Source: USCA
49
Table to right shows our estimate of ‘15 Midstream capital market needs for our universe.
Typical need for MLP equity, with the largest needs at EPD, PAA, DPM, MWE and OKS.
Growing use of ATM programs greatly reduces need for MLPs to issue equity through traditional follow-on offerings.
Minimal need for C-Corp equity with the exception of KMI.
Company Equity NeedsEstimated ATM
UsageDebt Needs*
C Corps
LNG $0 $0 $2,800
KMI $1,850 $1,850 $1,480
NFG $8 $0 $450
NI ($10) $0 $635
OKE $0 $0 $0
PAGP $0 $0 $0
SEMG $0 $0 $0
SE $0 $0 $756
TRGP $0 $0 $0
WMB $0 $0 $0
MLPs
CQP $0 $0 $3,250
DPM* $1,050 $300 $1,050
EPD $1,150 $200 $1,840
EQM* $425 $0 $850
MMP $0 $0 $800
MWE $900 $900 $900
OKS $875 $500 $662
PAA* $1,100 $800 $1,100
RRMS* $175 $0 $175
SEP $700 $350 $700
NGLS $280 $280 $700
WPZ $250 $250 $2,700
*Debt needs are net of refinancing current maturities
*DPM assumes $1,500mm of dropdowns from DCP Midstream LLC
*EQM assumes $1,00mm dropdown from EQT
*PAA assumes $800mm of acquisitions
*RRMS assumes $400mm of dropdowns from SEMG
USCA 2015 Midstream Capital Market Needs ($mm)
Valuation
50
51
Source: USCA, Company reports
Company2014E
DPU
2015E
DPU
DPU
GrowthCoverage
Excess/(Shortfall)
Distributions ($mm)
CQP $1.70 $1.70 0.0% na ($228) None na
DPM $3.06 $3.26 6.5% 1.27x $106 None na
EPD $1.45 $1.56 7.2% 1.25x $778 None $3.7B-$4.2B capex
EQM $2.14 $2.62 22.4% 1.57x $116 At least 3c/quarter increase through at least '16 $380-410mm growth capex
MMP $2.62 $3.06 16.8% 1.30x $208 15% distribution growth na
MWE $3.54 $3.80 7.3% 1.04x $31 7% distribution growth na
NGLS $3.16 $3.54 12.2% 1.03x $63 11-13% distribution growth; 1-1.2x coverage $60/60c to $80-80c NGLs
OKS $3.07 $3.31 7.8% 1.03x $28 6-8%/yr dist. growth; EBITDA $1.88B; DCF $1.4B G&P volumes +17%. $4 gas, 89c NGLs (C3+)
PAA $2.61 $2.87 9.8% 1.22x $234 7-10% dist. growth; EBITDA $2.425B; DCF $1.7B $1.5-$2.0B capex
RRMS $2.22 $2.78 25.2% 1.22x $28 None na
SEP $2.29 $2.45 7.0% 1.22x $211 Target 8-9%/yr growth na
WPZ* $3.69 $3.65 -1.1% 1.02x $78 $3.65 distribution, ~$5B EBITDA, 1.1x coverage Gas $4.25, Oil $92, $1.25 propane, 58c ethylene
LNG $0.00 $0.00 0.0% na na None na
KMI $1.74 $2.00 14.9% 1.13x $568 $2.00/sh dividend na
OKE $2.33 $2.65 13.5% 1.09x $48 12-15% dividend growth na
PAGP $0.74 $0.92 23.5% 1.00x $0 26% dividend growth 10% distribution growth at PAA
SEMG $1.15 $1.76 53.0% 1.16x $88 None na
SE $1.38 $1.52 10.2% 1.15x $151 12c/yr dividend increase, but latest was 14c na
TRGP $2.85 $3.83 34.6% 1.17x $34 35% dividend growth na
WMB $1.96 $2.46 25.7% 1.09x $160 $2.46/sh dividend $400mm excess coverage
*WPZ '14 distribution is pre-ACMP merger, while '15 is post, so not comparable
USCA Research Estimates
Company Guidance Key Assumptions
USCA Midstream Valuation Stats
Source: USCA, Bloomberg
52
As of 1/8/14
Company Name Ticker USCA Rating Target PriceCurrent
Price% Upside
Price
Change YTD
52 Week
High
52 Week
Low
Shares
(mm)
Market Cap
($mm)EV ($mm)
Latest
DividendYield
C Corps
Cheniere Energy Inc LNG Overweight $86 68.25$ 26.0% -3.1% 85.00$ 40.43$ 236.8 16,165$ 16,165$ -$ 0.00%
Cheniere Energy Partners LP Holdings CQH Buy $32 22.68$ 41.1% 0.7% 27.15$ 17.81$ 231.7 5,255$ 5,255$ 0.02$ 0.34%
Kinder Morgan Inc KMI Overweight $47 42.34$ 11.0% 0.1% 43.18$ 30.81$ 2,125.1 89,978$ 125,458$ 0.44$ 4.16%
National Fuel Gas NFG Overweight $79 68.47$ 15.4% -1.5% 78.79$ 64.31$ 84.2 5,765$ 7,461$ 0.39$ 2.25%
NiSource Inc NI Hold $43 42.93$ 0.2% 1.2% 44.91$ 32.75$ 315.7 13,553$ 23,280$ 0.26$ 2.42%
ONEOK, Inc OKE Hold $54 45.26$ 19.3% -9.1% 71.19$ 43.36$ 208.2 9,423$ 13,717$ 0.59$ 5.21%
Plains GP Holdings LP PAGP Overweight $29 25.20$ 15.1% -1.9% 32.58$ 22.51$ 606.0 15,272$ 15,272$ 0.20$ 3.22%
SemGroup SEMG Overweight $76 64.17$ 18.4% -6.2% 88.99$ 59.30$ 43.5 2,791$ 3,517$ 0.30$ 1.87%
Spectra Energy SE Hold $37 34.14$ 8.4% -6.0% 43.12$ 32.50$ 671.0 22,908$ 33,564$ 0.37$ 4.34%
Targa Resources Corp TRGP Overweight $115 97.89$ 17.5% -7.7% 160.97$ 86.41$ 42.1 4,125$ 4,217$ 0.73$ 2.99%
Williams Companies WMB Hold $48 43.02$ 11.6% -4.3% 59.77$ 38.43$ 747.5 32,156$ 36,715$ 0.57$ 5.30%
MLPs
Cheniere Energy Partners CQP Buy $41 31.18$ 31.5% -2.6% 34.60$ 25.08$ 337.8 10,533$ 19,522$ 0.43$ 5.45%
DCP Midstream Partners DPM Overweight $54 46.05$ 17.3% 1.4% 57.98$ 40.09$ 112.9 5,200$ 7,445$ 0.77$ 6.69%
Enterprise Products EPD Buy $44 34.44$ 27.8% -4.7% 41.38$ 30.71$ 1935.0 66,642$ 85,452$ 0.37$ 4.30%
EQT Midstream Partners EQM Buy $107 82.33$ 30.0% -6.4% 102.51$ 59.00$ 61.9 5,098$ 5,436$ 0.55$ 2.67%
Magellan Midstream Partners MMP Overweight $100 78.84$ 26.8% -4.6% 90.08$ 60.23$ 227.1 17,902$ 20,891$ 0.67$ 3.39%
MarkWest Energy Partners MWE Buy $84 59.66$ 40.8% -11.2% 80.79$ 58.62$ 184.0 10,980$ 14,411$ 0.89$ 5.97%
Oiltanking Partners OILT Hold $52 44.47$ 15.8% -4.5% 54.95$ 30.88$ 83.1 3,697$ 3,876$ 0.27$ 2.45%
ONEOK Partners OKS Overweight $47 40.05$ 17.4% 1.1% 59.67$ 36.67$ 250.3 10,026$ 16,080$ 0.78$ 7.74%
Plains All American PAA Overweight $57 51.15$ 11.4% -0.3% 61.09$ 43.61$ 372.0 19,030$ 28,170$ 0.68$ 5.28%
Rose Rock Midstream RRMS Buy $54 43.62$ 23.8% -4.0% 62.79$ 35.63$ 32.7 1,427$ 1,891$ 0.58$ 5.27%
Spectra Energy Partners SEP Hold $54 54.32$ -0.6% -4.7% 60.07$ 41.53$ 295.5 16,049$ 21,887$ 0.58$ 4.24%
Targa Resources Partners NGLS Hold $53 46.37$ 14.3% -3.2% 83.49$ 40.17$ 115.8 5,368$ 8,506$ 0.80$ 6.88%
Williams Partners WPZ Hold $48 42.78$ 12.2% -4.4% 57.29$ 40.48$ 439.7 18,811$ 30,798$ 0.93$ 8.68%
Indices
S&P 500 SPX Index 2,062.14$ 2,093.55$ 1,737.92$ 2.1%
Crude Oil - WTI CL1 Comdty 49.00$ 107.73$ 46.83$
Natural Gas NG1 Comdty 2.96$ 6.49$ 2.81$
Alerian MLP Index AMZ Index 445.45$ 540.01$ 407.64$ 6.4%
MSCI US REIT Index RMZ Index 1,173.23$ 1,176.32$ 893.43$ 3.6%
USCA Valuation Methodology
53
2014 saw a wide scale shift to “Yield vs. Growth” methodology as the sector reached new highs. Whether stubbornly or wisely, we continue to stick with our discounted cash flow approach. So we review that again below as reference.
For MLPs, we model distributions through 2020 and then apply a terminal growth thereafter. We use a three-pronged approach to determine the cost of equity and thus discount rate (three approaches outlined below). We then average the three valuations.
• Traditional CAPM: Uses a stock’s beta to measure riskiness of investment relative to the market.
• Growth Adjusted Cash Yield (GACY): Uses projected distribution yield for the next year plus an adjustment for expected long-term distribution growth. Provides a proxy for what level of return investors expect over the long term.
• GP Adjusted Distribution Discount Model (DPM): Uses average annual forecasted distributions (both GP and LP) over the next three years divided by the average number of forecasted outstanding LP units over the next three years divided by the current unit price. Helps account for higher capital costs associated with MLPs who have high GP payout ratios.
For GPs, we mark any LP units owned to market. For GP cash flow value, we forecast GP distributions through 2020 and then apply a terminal growth rate. We then apply the appropriate tax rate to those cash flows and then discount those at a consistent 10% discount rate. For anything else, we apply an industry multiple to forward year EBITDA (‘16 in this case). We then net out the debt (including off balance sheet) and arrive at an equity value per share.
As there are many who look to Yield vs. Growth metrics, we also include a chart of consensus metrics.
Yield vs. Growth Metric
Source: Bloomberg, USCA
54
EEP
ETPEPD
OKS
PAANGLS
WPZ
CEQP
ETE
ENLC
KMI
NSH
OKE
PAGP
SEMG
SE
TRGP
WGP
WMB
ACMP
APLDPM
ENLKMWE
FISHRGP
SMLPWES
BPL
CAPLGEL
GLP
MMP
NGL
NS
OILTRRMS
SRLP
SXL
SUN
WPT
BWP
EQM
SEP
TEP
TCP
DKL
HEP
MPLX
PSXP
TLLP
VLP
WNRL
CQP
SXCP
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
1% 2% 3% 4% 5% 6% 7% 8% 9% 10%
Co
nse
nsu
s D
istr
ibu
tio
n/D
ivid
en
d G
row
th (
'15
E vs
. '1
4 E
)
Current Yield
IMPORTANT DISCLOSURES
55
ANALYST CERTIFICATION We, Becca Followill and James Carreker, do hereby certify that the recommendations and opinions expressed in this presentation accurately reflect our personal views about any and all of the subject securities or issues discussed herein. Furthermore, no part of our compensation was, is, or will be, directly or indirectly, related to the specific recommendations or views expressed herein. We do not own any shares directly or indirectly (or any derivative thereof) of the company that is subject to this research report. Neither we nor any member of our households serves as an officer, director or advisory board member of any company that is subject to this presentation. Employees of U.S. Capital Advisors LLC (“USCA” or “the Firm”) not involved in the preparation of this report may have investments in securities or derivatives of securities of companies mentioned in this report, and may buy, sell, or trade them in ways different from, or in a manner inconsistent with, the recommendations and opinions expressed in this report. IMPORTANT DISCLOSURES Analysts’ compensation is not based on investment banking revenue and the analysts are not compensated by the subject companies. USCA provided and received compensation for providing investment banking services for the following subject companies within the past 12 months: Rice Midstream Partners (RMP) and Regency Energy Partners (RGP). Within the next three months USCA may attempt to seek compensation for investment banking services from the companies mentioned within this report.
IMPORTANT DISCLOSURES
56
Opinion Key: USCA uses a Buy, Overweight, Hold, Underweight and Sell rating system. BUY - The stock has among the best combination of risk/reward and positive company specific catalysts within the sector. Stock is expected to trade higher on an absolute basis and be a top performer relative to peer stocks over the next 12 months. OVERWEIGHT - The stock has above average risk/reward and is expected to outperform peer stocks over the next 12 months. HOLD - The stock has average risk/reward and is expected to perform in line with peer stocks over the next 12 months. UNDERWEIGHT - The stock has below average risk/reward and is expected to underperform peer stocks over the next 12 months. SELL - The stock's risk/reward is skewed to the downside with possible negative company specific catalysts or excessive valuation. The stock is expected to trade lower on an absolute basis and be among the worst performers relative to peer stocks over the next 12 months. Risks that may impede achievement of price target(s): Industry wide risks include but are not limited to environmental and regulatory for both pipeline and E&P, aging infrastructure and availability of midstream infrastructure to accommodate new production. Competition for and availability of service crews and drilling rigs. Commodity prices, the economic outlook, access to capital markets. Interest rates. Asset recontracting. Cost overruns.
IMPORTANT DISCLOSURES
57
Price Target Methodology: C-Corps For C-Corps, our price targets are, generally, based on a traditional sum of the parts analysis. For traditional pipes and midstream assets, we value at 8-12x EBITDA multiples (usually forward year unless it doesn’t represent a good run rate). LP units are marked to current market. GP values are determined using a discounted cash flow of projected distributions and then tax effected. MLPs For MLPs, we average three different valuations as we have yet to find one pure way to value MLPs that captures the many nuances – current yield, growth, GP IDRs, equity to fund growth, etc. For all three methods, we start with six-year projections of LP distributions and assume a terminal growth rate. The three valuation methods – Traditional CAPM, Growth Adjusted Cash Yield, and GP Adjusted Distribution Discount Model – each yield a different cost of equity, which is then used as the discount rate against the projected distributions and terminal growth rates. Traditional CAPM is a straight forward traditional use of the Capital Asset Pricing Model. Growth Adjusted Cash Yield uses projected yield plus an adjustment for expected long-term distribution growth. GP Adjusted Distribution Discount Model uses average annual forecasted distributions for both the GP and LP for the next three years divided by the average number of forecasted LP units over the next three years divided by the current LP unit price. In our view, this method helps account for the higher cost of capital associated with GP IDRs.
Distribution of Ratings (as of January 9, 2015): Historical Ratings and Price Targets may be found by clicking the link: USCA Rating and Price Target History For hard a hard copy of our price target/ratings history, please call 888-601-USCA (8722), or write to U.S. Capital Advisors, 1330 Post Oak Blvd., Suite 900, Houston, TX, 77056. For a list of common terms and abbreviations, please go to www.uscallc.com/assets/pdf/Glossary.pdf © Copyright 2015 U.S. Capital Advisors LLC, all rights reserved. This information is confidential and may not be disclosed, copied or disseminated, in whole or in part, without the prior written permission of USCA. This communication is based on information which USCA believes is reliable; however, the Firm does not represent or warrant its accuracy. The viewpoints and opinions expressed in this communication represent the views of the authors as of the date of this report. These viewpoints and opinions may be subject to change without notice and USCA will not be responsible for any consequences associated with reliance on any statement or opinion contained in this communication. This report does not provide individually tailored investment advice. It has been prepared without regard to the individual financial circumstances and objectives of persons who may receive it and for this reason, this message should not be considered as an offer or solicitation to buy or sell any securities. Securities offered through USCA Securities LLC; Investment advisory services offered through USCA RIA LLC and Condera Advisors LLC; Municipal advisory services offered through USCA Municipal Advisors LLC; Insurance products offered through USCA Insurance Agency LLC; Tax planning and family office services offered through USCA Family Estate Services LLC
IMPORTANT DISCLOSURES
Recommendation Count Percent Investment Banking
Relationship Count Percent
Overweight/Buy 33 55% Overweight/Buy 2 6%
Hold 27 45% Hold 0 0%
Underweight/Sell 0 0% Underweight/Sell 0 0%
58
59
Contact Information
David King Managing Partner [email protected] 713-366-0530 Robert Stanton Managing Director [email protected] 713-366-0504 Leslie Rich Director [email protected] 713-366-0532
Barry Guinn Senior Managing Director [email protected] 713-366-0534 Rachel Zick Director [email protected] 713-366-0531
Rae Lees Managing Director [email protected] 713-366-0533 Gil Beer Director [email protected] 713-366-0518
Sales Team Trading Team
Bart Barnett Managing Director [email protected] 713-366-0542
Research Team
Becca Followill Senior Managing Director [email protected] 713-366-0557 James Carreker Director [email protected] 713-366-0558
Dan Fidell Managing Director [email protected] 713-366-0500 Sarika Patel Research Analyst [email protected] 713-366-0559
Cameron Horwitz Managing Director [email protected] 713-366-0541 Kyle Landau Research Analyst [email protected] 713-366-0548
Denise Cardozo Research Assistant [email protected] 713-366-0563 Colin Crosby Analyst [email protected] 713-366-0547
Brad Stammen Managing Director [email protected] 713-366-0535 Clint Turner Director [email protected] 713-366-0536