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| 8-K - 2017 12 06 NS 8-K [REG FD WELLS FARGO CONFERENCE] - NuStar Energy L.P. | a20171206ns8-kregfdwellsfa.htm |
Pipeline, MLP and Utility
Symposium
2017 Wells Fargo
December 6, 2017
Exhibit 99.1
Forward-Looking Statements
2
Statements contained in this presentation other than statements of historical fact are forward-looking
statements. While these forward-looking statements, and any assumptions upon which they are based,
are made in good faith and reflect our current judgment regarding the direction of our business, actual
results will likely vary, sometimes materially, from any estimates, predictions, projections, assumptions or
other future performance presented or suggested in this presentation. These forward-looking statements
can generally be identified by the words "anticipates," "believes," "expects," "plans," "intends,"
"estimates," "forecasts," "budgets," "projects," "could," "should," "may" and similar expressions. These
statements reflect our current views with regard to future events and are subject to various risks,
uncertainties and assumptions.
We undertake no duty to update any forward-looking statement to conform the statement to actual
results or changes in the company’s expectations. For more information concerning factors that could
cause actual results to differ from those expressed or forecasted, see NuStar Energy L.P.’s annual report
on Form 10-K and quarterly reports on Form 10-Q, filed with the SEC and available on NuStar’s website at
www.nustarenergy.com.
We use financial measures in this presentation that are not calculated in accordance with generally
accepted accounting principles (“non-GAAP”) and our reconciliations of non-GAAP financial measures to
GAAP financial measures are located in the appendix to this presentation. These non-GAAP financial
measures should not be considered an alternative to GAAP financial measures.
NuStar Overview
Two Publicly Traded Companies
4
1 – On November 30, 2017, NuStar issued 6,000,000 of its 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Units at a price of $25.00 per unit for net proceeds of ~$145 million
IPO Date: 4/16/2001 G.P. Interest in NS
Common Unit Price (12/4/17): $30.05 ~11% Common L.P. Interest in NS
Annualized Distribution/Common Unit: $4.38 Incentive Distribution Rights in NS (IDR)
Yield (12/4/17): 14.6% ~11% NS Distribution Take
Market Capitalization: $3.5 billion IPO Date: 7/19/2006
Enterprise Value: $7.1 billion Unit Price (12/4/17): $14.65
Credit Ratings Annualized Distribution/Unit: $2.18
Moody's: Ba1/Negative Yield (12/4/17): 14.9%
S&P: BB/Negative Market Capitalization: $0.6 billion
Fitch: BB/Stable Enterprise Value: $0.7 billion
NYSE: NSH
NYSE: NS
William E. Greehey
9.2 million NSH Units
21.4% Membership Interest
Public Unitholders
93.1 million Common
9.1 million Series A Preferred
15.4 million Series B Preferred
6.0 million Series C Preferred1
Other
Public Unitholders
33.8 million NSH Units
78.6% Membership Interest
Assets:
81 terminal and storage facilities
Approximately 96 million barrels of storage capacity
Approximately 9,300 miles of pipelines
Corpus Christi, TX –
Destination for South Texas
Crude Oil Pipeline System
St. James, LA – 9.9MM bbls
Pt. Tupper, Nova Scotia – 7.8MM bbls
Linden, NJ – 4.6MM bbls
St. Eustatius –
14.4MM bbls
3.8MM bbls
Large and Diverse Geographic Footprint with
Assets in Key Locations
5
Permian Crude System
(Midland Basin) – Crude Oil
Gathering, Transportation
and Storage
Focus Has Been on De-Risking the
Business
De-Risk the Business and put Ourselves
in a Position to Grow
7
Starting in 2014, we began to focus on...
Strengthening
Our Balance
Sheet
Restoring Our
Distribution
Coverage
De-Risking Our
Business
Refocusing On
Our Core Pipeline
and Storage
Business
With solid execution by our management team and our
employees, we set the stage for future growth
Refined Product Pipelines
Crude Oil Pipelines
Ammonia Pipeline
Refined Product Terminals
Crude Oil Storage
Fuels Marketing
Recently exited our Crude Oil and Fuel Oil Trading operations – 2017 EBITDA neutral
The only operations remaining are our bunkering operations at Texas City and St. Eustatius
and our butane blending operations
Storage Pipeline
45%
51%
4%
Percentage of Annual Segment EBITDA1
Successfully De-Risked the Partnership - Exited
the Majority of our Margin-Based Businesses
8
2014
2016
2011
1 - Please see slides 27-30 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures
49%
34%
17%
49%
50%
Take or Pay
Contractual -
30%
Structurally
Exclusive –
63%
Other – 7%
Crude – 47%
Refined
Products -
45%
Other –
9%
Pipeline Segment – Committed
and Diversified
Pipeline Receipts by Commodity
(TTM as of 9/30/17)
*Other includes ammonia, naphtha and NGL’s
~93% committed
through take or pay
contracts or through
structural exclusivity
(uncommitted lines
serving refinery
customers with no
competition)
Committed Pipeline Revenues
(As of 9/30/17)
9
Storage Segment – Effectively Full
Storage Lease Utilization
(as of 9/30/2017)
Storage Lease Renewals
(% as of 9/30/2017)
96% of
Leasable
Storage
Effectively
Full
10
38%
42%
20%
< 1 Year 1 to 3 Years > 3 Years
$208
$242 $256
$279 $287 $277 $287
$335 $333
$186
$190
$199
$198
$211
$277
$323
$355 $338
2008 2009 2010 2011 2012 2013* 2014 2015 2016
Storage Segment Pipeline Segment * Adjusted for Goodwill Impairment Loss
$610
$394
$432
$455
$477
$498
$554
$690
$671
Historical Pipeline and Storage Segment EBITDA1 ($ in millions)
Base Business EBITDA – Consistent
Performance in Various Market Conditions
Great Recession
Backwardated Market Structure
Oil Price Crash
Shale Boom
1 - Please see slides 27-30 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures 11
Acquisition Overview
Permian Crude System Overview
Permian Crude System
Overview
13
On May 4, NuStar acquired the Permian Crude System from First Reserve Energy
Infrastructure Fund for ~$1.5 billion in cash
Our system is a leading crude oil gathering, transportation and storage system in the “core of the
core” of the Midland Basin in the Permian
This acquisition provides us a significant growth platform in the highest-growth U.S. shale
play backed by strong customers and long-term contracts
The Permian Basin currently represents approximately 40% of all U.S. onshore rig activity
Significant growth prospects through volume ramp from existing producers, bolt-on acquisitions and
larger takeaway capacity opportunities
Diversified, high-quality customer portfolio with attractive long-term fee-based contracts
Rapid volume growth expected in 2017 and 2018
Over 514,000 acres dedicated to our system
Source for U.S. onshore rig activity Baker Hughes data
14
Our System is Located in the Center of the Permian
Basin, the U.S. Basin With the Strongest Performance
and Growth Outlook
Permian rig counts continue to rise, now up 190% (148% increase in the
Midland) since the low in May 2016
Midland rigs are up 25% since April 2017
This year 2,646 new drilling permits have been approved and 1,556 new
wells have been spudded in the Midland Basin
Our system overlays the areas with highest activity
Production has started to ramp up as the increase in drilling activity has
resulted in incremental wells coming online
2017 Drilling Activity
Permian Rigs
One Year
Ago
Source(s): Drilling Info, Baker Hughes data
Our Permian Crude System is in the Most
Active Areas of the Midland
Permian Basin has
380 rigs operating,
representing ~42% of
all U.S. onshore rig
activity
- 3.3x the rig count
in the Bakken /
Eagle Ford
combined
Our Permian Crude
System Overview:
Fully integrated crude
platform
~625 miles of
pipeline with
412,000 bbls/d of
current capacity
1 million bbls of
storage capacity
Pipeline gathering
with over 514,000
dedicated acres
Nearly 5 million
acres of “Areas of
Mutual Interest,” or
“AMI”
Delivery points into
Midland, Colorado City
and Big Spring
Source: Rig count per Baker Hughes data
Rigs by Top U.S. Play
Rigs by Permian
Sub-Basin
Rigs by Midland
Counties
Navigator Counties
15
10
26
30
38
42
48
65
66
380
0 200 400
Granite Wash
DJ-Niobrara
Utica
Haynesville
Marcellus
Bakken
Eagle Ford
Cana
Woodford
Permian
20
21
155
184
0 100 200
Other
Central
Basin
Platform
Midland
Delaware
1
1
2
2
4
11
15
13
17
18
28
43
0 25 50
Dawson
Ector
Borden
Irion
Gaines
Andrews
Upton
Glasscock
Reagan
Howard
Martin
Midland
16
Our Permian Crude System is an Integrated
Crude System
South Texas Crude Pipeline System
As expected, the Eagle Ford has seen a modest recovery, with rig counts up a significant 35 rigs from its low
on July 29, 2016 (Source: Baker Hughes)
Even with this recovery, pipeline capacity in the Eagle Ford currently exceeds production and production is below
aggregate minimum volume commitments
Although Eagle Ford production increased modestly this year, our South Texas System volumes have not
improved much
Most shippers have T&D commitments to move barrels on Houston-bound pipelines, as well as on pipelines to
Corpus Christi
Houston-bound rates are higher, so shippers are pushing any incremental volumes there under their minimum
volume commitments
We continue to explore using the available capacity as the first step in a long-haul solution to bring barrels
from the Permian
We remain well-positioned to benefit from EBITDA growth with no incremental capex when volumes increase
Approximately 45-50% of T&D commitments to NuStar begin rolling off in the 3rd quarter of 2018
We currently do not expect our customers to renew these T&D commitments
Expect our customers to convert to walk-up shippers
18
South Texas Crude Pipeline
System Update
Finance Update
$374 $302 $328 $288
$166
$360
to
$380
$360
to
$390
$316
$143
$96
$1,500
$0
$500
$1,000
$1,500
$2,000
2012 2013 2014 2015 2016 2017
Forecast
2018
Forecast
Internal Growth Acquisitions
$262
TexStar
Acquisition
Internal Growth Spending Expected to be $360 to
$380 Million in 2017 and $360 to $390 Million in 2018
(Dollars in Millions)
2017 Total Capital Spending (excluding Navigator Acquisition price), which includes Reliability Capital, is
expected to be in the range of $410 to $450 million
2018 Total Capital Spending, which includes Reliability Capital, is expected to be in the range of $425 to $475
million
2012 to 2018
Average Internal Growth
Spend $313 Million per Year
Linden JV
Acquisition
Martin
Terminal
Acquisition
Navigator
Acquisition
20
$690
$431
Expansion of our Permian Crude System operations
Expansion of our South Texas Crude Oil Pipeline System
Pursuing a solution to link the two systems and provide optionality to Corpus Christi, TX
Crude Oil
Pipeline
Expansion
South Texas refined product supply opportunities
Gulf Coast & Northern Mexico NGL opportunities
Refined Product
Pipeline
Expansion
Terminal
Expansion
Growth Projects – Currently
Evaluating $1.0 to $1.5 Billion
Opportunities to expand Northeast operations
Unit train and pipeline connection opportunities at our St. James Terminal
Renewable opportunities on the East and West Coast
21
$878
$350
$450
$300 $250
$550
$365
$403
$46
$0
$250
$500
$750
$1,000
$1,250
2017 2018 2019 2020 2021 2022 2027 2038-2041
Receivables Financing
Sub Notes
GO Zone Financing
Senior Unsecured Notes
Revolver$806
$1,374
Just $350 Million of Debt Maturing
Before 2020 (Dollars in Millions)
Callable in 2018, but
final maturity in 2043
22 Note: Debt maturities as of 9/30/17
2017 & 2018
Guidance Summary
($ in Millions)
Annual EBITDA1
G&A
Expenses
Reliability Capital
Spending
Strategic Capital
Spending
2017 Guidance $575 - $625 $110 - $120 $50 - $70 $360 - $380
2018 Guidance $675 - $725 $100 - $110 $65 - $85 $360 - $390
1 - Please see slides 27-30 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures 23
Appendix
Capital Structure
($ in Millions)
As of September 30, 2017
(Unaudited)
$1.5 billion Credit Facility $878
NuStar Logistics Notes (4.75%) 250
NuStar Logistics Notes (4.80%) 450
NuStar Logistics Notes (5.625%) 550
NuStar Logistics Notes (6.75%) 300
NuStar Logistics Notes (7.65%) 350
NuStar Logistics Sub Notes (7.625%) 403
GO Zone Bonds 365
Receivables Financing 46
Short-term Debt & Other 59
Total Debt $3,651
Availability under $1.5 billion Credit Facility (as of September 30, 2017): ~$864 million
- Debt to EBITDA calculation per Credit Facility of 4.8x (as of September 30, 2017)
1 – Please see slides 27-30 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures 25
Capital Structure (continued)
($ in Millions)
As of September 30, 2017
(Unaudited)
Partner’s Equity
Series A Preferred Units $218
Series B Preferred Units 372
Common Equity, General Partner and AOCI 1,830
Total Partners’ Equity 2,420
Total Capitalization $6,071
26
Reconciliation of Non-GAAP
Financial Information
27
NuStar Energy L.P. utilizes financial measures, such as earnings before interest, taxes, depreciation and amortization (EBITDA), distributable cash flow
(DCF) and distribution coverage ratio, which are not defined in U.S. generally accepted accounting principles (GAAP). Management believes these financial
measures provide useful information to investors and other external users of our financial information because (i) they provide additional information about the
operating performance of the partnership’s assets and the cash the business is generating, (ii) investors and other external users of our financial statements
benefit from having access to the same financial measures being utilized by management and our board of directors when making financial, operational,
compensation and planning decisions and (iii) they highlight the impact of significant transactions.
Our board of directors and management use EBITDA and/or DCF when assessing the following: (i) the performance of our assets, (ii) the viability of potential
projects, (iii) our ability to fund distributions, (iv) our ability to fund capital expenditures and (v) our ability to service debt. In addition, our board of directors
uses a distribution coverage ratio, which is calculated based on DCF, as one of the factors in its determination of the company-wide bonus and the vesting of
performance units awarded to management. DCF is a widely accepted financial indicator used by the master limited partnership (MLP) investment community
to compare partnership performance. DCF is used by the MLP investment community, in part, because the value of a partnership unit is partially based on its
yield, and its yield is based on the cash distributions a partnership can pay its unitholders.
None of these financial measures are presented as an alternative to net income, or for any period presented reflecting discontinued operations, income from
continuing operations. They should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with GAAP. For
purposes of segment reporting, we do not allocate general and administrative expenses to our reported operating segments because those expenses relate
primarily to the overall management at the entity level. Therefore, EBITDA reflected in the segment or project reconciliations exclude any allocation of general
and administrative expenses consistent with our policy for determining segmental operating income, the most directly comparable GAAP measure.
Reconciliation of Non-GAAP
Financial Information (continued)
28
2008 2009 2010 2011 2012 2013 2014 2015 2016
Operating income 135,086$ 139,869$ 148,571$ 146,403$ 158,590$ 208,293$ 245,233$ 270,349$ 248,238$
Plus depreciation and amortization expense 50,749 50,528 50,617 51,165 52,878 68,871 77,691 84,951 89,554
EBITDA 185,835$ 190,397$ 199,188$ 197,568$ 211,468$ 277,164$ 322,924$ 355,300$ 337,792$
2008 2009 2010 2011 2012 2013 2014 2015 2016
Operating income (loss) 141,079$ 171,245$ 178,947$ 196,508$ 198,842$ (127,484)$ 183,104$ 217,818$ 214,801$
Plus depreciation and amortization expense 66,706 70,888 77,071 82,921 88,217 99,868 103,848 116,768 118,663
EBITDA 207,785$ 242,133$ 256,018$ 279,429$ 287,059$ (27,616)$ 286,952$ 334,586$ 333,464$
Impact from non-cash goodwill impairment charges 304,453
Adjusted EBITDA 276,837$
2011 2014 2016
Operating income 71,854$ 24,805$ 3,406$
Plus depreciation and amortization expense 20,949 16 -
EBITDA 92,803$ 24,821$ 3,406$
The following is a reconciliation of operating income to EBITDA for the fuels marketing segment (in thousands of dollars):
Year Ended December 31,
The following is a reconciliation of operating income (loss) to EBITDA for the storage segment (in thousands of dollars):
Year Ended December 31,
The following is a reconciliation of operating income to EBITDA for the pipeline segment (in thousands of dollars):
Year Ended December 31,
Reconciliation of Non-GAAP
Financial Information (continued)
29
Consolidated Consolidated Consolidated
Income from continuing operations 218,674$ 214,169$ 150,003$
Interest expense, net 81,539 131,226 138,350
Income tax expense 18,555 10,801 11,973
Depreciation and amortization expense 161,773 191,708 216,736
EBITDA from continuing operations 480,541 547,904 517,062
General and administrative expenses 103,050 96,056 98,817
Other expense (income), net 3,573 (4,499) 58,783
Equity in earnings of joint ventures (11,458) (4,796) -
Segment EBITDA 575,706$ 634,665$ 674,662$
Segment
EBITDA
Segment
Percentage (a)
Segment
EBITDA
Segment
Percentage (a)
Segment
EBITDA
Segment
Percentage (a)
Pipeline segment (see previous slide for EBITDA reconciliation) 197,568$ 34% 322,924$ 51% 337,792$ 50%
Storage segment (see previous slide for EBITDA reconciliation) 279,429 49% 286,952 45% 333,464 49%
Fuels marketing segment (see previous slide for EBITDA reconciliation) 92,803 16% 24,821 4% 3,406 1%
Elimination/consolidation 5,906 1% (32) - - -
Segment EBITDA 575,706$ 100% 634,665$ 100% 674,662$ 100%
(a) Segment Percentage calculated as segment EBITDA for each segment divided by total segment EBITDA.
The following are the non-GAAP reconciliations of income from continuing operations to EBITDA from continuing operations and for the calculation of EBITDA for each of our segments as a percentage of total
segment EBITDA (in thousands of dollars, except percentage data):
Year Ended December 31, 2011 Year Ended December 31, 2016Year Ended December 31, 2014
Reconciliation of Non-GAAP
Financial Information (continued)
30
The following are reconciliations of projected net income to projected EBITDA (in thousands of dollars):
2017 2018
Projected net income $ 140,000 - 170,000 $ 195,000 - 225,000
Projected interest expense, net 170,000 - 175,000 180,000 - 185,000
Projected income tax expense 5,000 - 10,000 5,000 - 10,000
Projected depreciation and amortization expense 260,000 - 270,000 295,000 - 305,000
Projected EBITDA $ 575,000 - 625,000 $ 675,000 - 725,000
For the Four Quarters Ended
September 30, 2017
Net income 111,726$
Interest expense, net 162,258
Income tax expense 9,978
Depreciation and amortization expense 249,640
EBITDA 533,602
Other expense (a) 63,671
Equity awards (b) 10,196
Mark-to-market impact on hedge transactions (c) 1,173
Pro forma effect of acquisitions (d) 56,006
Material project adjustments (e) 12,143
Consolidated EBITDA, as defined in the Revolving Credit Agreement 676,791$
Total consolidated debt 3,660,479$
NuStar Logistics' 7.625% fixed-to-floating rate subordinated notes (402,500)
Proceeds held in escrow associated with the Gulf Opportunity Zone Revenue Bonds (41,476)
Consolidated Debt, as defined in the Revolving Credit Agreement 3,216,503$
Consolidated Debt Coverage Ratio (Consolidated Debt to Consolidated EBITDA) 4.8x
(a)
(b)
(c)
(d)
(e)
Year Ended December 31,
This adjustment represents the percentage of the projected Consolidated EBITDA attributable to any Material Project, as defined in the Revolving
Credit Agreement, based on the current completion percentage.
This adjustment represents the unrealized mark-to-market gains and losses that arise from valuing certain derivative contracts, as well as the
associated hedged inventory. The gain or loss associated with these contracts is realized in net income when the contracts are settled.
The following is the non-GAAP reconciliation for the calculation of our Consolidated Debt Coverage Ratio, as defined in our $1.75 billion revolving credit
agreement (the Revolving Credit Agreement) (in thousands of dollars, except ratio data):
This adjustment consists mainly of a $58.7 million non-cash impairment charge on the Axeon term loan in the fourth quarter of 2016.
This adjustment represents the pro forma effects of the Martin Terminal Acquisition and the Navigator Acquisition as if we had completed the
acquisitions on January 1, 2016.
This adjustment represents the non-cash expense related to the vestings of equity-based awards with the issuance of our common units.