As of May 3, 2024, Sunoco has successfully completed its acquisition of NuStar Energy L.P. Find out more here.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): August 16, 2017
NuStar Energy L.P.
(Exact name of registrant as specified in its charter)
Delaware | 001-16417 | 74-2956831 |
(State or other jurisdiction of incorporation) | (Commission File Number) | (I.R.S. Employer Identification No.) |
19003 IH-10 West San Antonio, Texas 78257 | ||
(Address of principal executive offices) | ||
(210) 918-2000 | ||
(Registrant’s telephone number, including area code) | ||
Not applicable | ||
(Former name or former address, if changed since last report.) | ||
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Item 7.01 Regulation FD Disclosure.
Senior management of NuStar Energy L.P. (the “Partnership”) is meeting with members of the investment community at the 2017 Citi One-on-One MLP/Midstream Infrastructure Conference in Las Vegas, Nevada on Wednesday, August 16, 2017, and Thursday, August 17, 2017. The slides attached to this report were prepared in connection with, and are being used during, the conference. The slides are included in Exhibit 99.1 to this report and are incorporated herein by reference. The slides will be available in the “Investors” section of the Partnership’s website at www.nustarenergy.com at 10:30 a.m. (Central Time) on August 16, 2017.
Item 9.01 Financial Statements and Exhibits.
(d) Exhibits.
Exhibit Number | EXHIBIT | |
Exhibit 99.1 | Slides used on August 16-17, 2017. | |
2
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
NUSTAR ENERGY L.P. | ||||
By: | Riverwalk Logistics, L.P. | |||
its general partner | ||||
By: | NuStar GP, LLC | |||
its general partner | ||||
Date: August 16, 2017 | By: | /s/ Amy L. Perry | ||
Name: | Amy L. Perry | |||
Title: | Senior Vice President, General Counsel - Corporate & Commercial Law and Corporate Secretary | |||
3
EXHIBIT INDEX
Exhibit Number | EXHIBIT | |
Exhibit 99.1 | Slides used on August 16-17, 2017. | |
4
One-on-One MLP / Midstream
Infrastructure Conference
2017 Citi
Aug 16 – 17, 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
IPO Date: 4/16/2001 G.P. Interest in NS
Common Unit Price (8/14/17): $40.32 ~11% Common L.P. Interest in NS
Annualized Distribution/Common Unit: $4.38 Incentive Distribution Rights in NS (IDR)
Yield (8/14/17): 10.9% ~11% NS Distribution Take
Market Capitalization: $4.4 billion IPO Date: 7/19/2006
Enterprise Value: $7.9 billion Unit Price (8/14/17): $21.65
Credit Ratings Annualized Distribution/Unit: $2.18
Moody's: Ba1/Negative Yield (8/14/17): 10.1%
S&P: BB+/Stable Market Capitalization: $0.9 billion
Fitch: BB/Stable Enterprise Value: $1.0 billion
NYSE: NSH
NYSE: NS
William E. Greehey
9.1 million NSH Units
21.1% Membership Interest
Public Unitholders
93.0 million Common
9.1 million Series A Preferred
15.4 million Series B Preferred
Other
Public Unitholders
33.9 million NSH Units
79.0% Membership Interest
Assets:
81 terminals
More than 96 million barrels of storage capacity
More than 9,300 miles of crude oil and refined product 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 and Restoring Coverage
De-Risking the Business and Restoring
Coverage
7
For the last 3 years, we have been focused 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 have now 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 36-40 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures
49%
34%
17%
49%
50%
Crude – 43%
Refined
Products -
48%
Other –
9%
Pipeline Segment – Committed
and Diversified
Pipeline Receipts by Commodity
TTM as of 6/30/17
*Other includes ammonia, naphtha and NGL’s
~92% committed
through take or pay
contracts or through
structural exclusivity
(uncommitted lines
serving refinery
customers with no
competition)
Committed Pipeline Revenues
(6/30/17 annual forecast)
Take or Pay
Contractual -
30%
Structurally
Exclusive –
62%
Other – 8%
9
Storage Segment – Effectively Full
Storage Lease Utilization
(as of 6/30/2017)
Storage Lease Renewals
(% as of 6/30/2017)
95% of
Leasable
Storage
Effectively
Full
10
38%
44%
18%
< 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
$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 36-40 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures 11
Coverage Restored in the Midst of Low Crude Oil
Price Environment – Putting Us in a Position to
Participate in Acquisitions
20
30
40
50
60
70
80
90
100
110
0.7
0.8
0.9
1
1.1
1.2
1.3
7/1/2014 2/1/2015 9/1/2015 4/1/2016 11/1/2016
C
ru
d
e
P
ri
c
e
C
o
v
e
ra
g
e
R
a
ti
o
NS Coverage Ratio Price of Crude One-Times
1.07x
0.98x
1.04x
1.12x 1.12x 1.11x
1.08x
1.12x
1.08x 1.07x 1.05x
Coverage Ratio1 (Trailing Twelve Months) vs Price of Crude
(October 2013 – March 2017)
3Q-16 3Q-14 4Q-14 1Q-15 2Q-15 3Q-15 4Q-15 1Q-16 2Q-16 4Q-16 1Q-17*
* Adjusted for Common Unit
Issuance for Navigator Financing
Second quarter 2017 coverage ratio of 0.59x – disproportionately impacted by $14 million
of Navigator acquisition and financing costs
Expect to begin covering distribution again as early as the second half of 2018
1 - Please see slides 36-40 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures 12
Acquisition Overview
Permian Crude System Overview
Permian Crude System
Overview
On May 4th, NuStar acquired the Permian Crude System by acquiring 100% of the
membership interests in Navigator Energy Services, LLC from First Reserve Energy
Infrastructure Fund for ~$1.5 billion in cash
Permian Crude System - a leading crude oil gathering, transportation and storage
system in the “core of the core” of the Midland Basin in the Permian
The Permian Basin currently represents approximately 40% of all U.S. onshore rig activity
Before this acquisition, we actively looked at opportunities in the Permian
For one reason or another, they did not meet our acquisition criteria or they included
assets that were either too risky or outside of our core areas of expertise
This acquisition provided a meaningful entry into the Permian and a significant growth
platform
The addition of the Permian Crude System, coupled with NuStar’s Eagle Ford position,
solidifies NuStar’s presence in two of the most prolific basins in the U.S.
The Permian Crude System assets are consistent with NuStar’s other crude oil operations,
with no first purchasing or gas processing exposure
14
Permian Crude System Overview
(continued)
Significant growth prospects through volume ramp from existing producers, bolt-on
acquisitions and larger takeaway capacity opportunities
Diversified, high-quality producer portfolio with attractive long-term fee-based contracts
Expected acquisition multiple of high single digits by 2020 as volumes ramp
Driven by existing producers with more than 514,000 dedicated acres on the system
15
Permian Crude System Highlights
Permian Crude System located in 5 of the 6 most active counties in the Midland Basin
Midland is one of the most economic, resilient and fastest growing basins in the U.S.
Permian, in aggregate, represents ~40% of all U.S. onshore rig activity
Permian has unparalleled resource potential
Decades of drilling inventory with breakeven economics at $35 - $45/bbl
“Core of the
Core” of the
Midland Basin
System structured with long-term, fixed-fee contracts
Mainline transportation with ~92,000 bbl/d of ship-or-pay volume commitments and
nearly 7 year average contract life
Pipeline gathering contract portfolio with an average life of over 10 years
440,000 bbls of storage contracted with an average life of nearly 7 years
Well-diversified customer base, including 16 upstream producers with a meaningful and active
presence in the Midland Basin
Stable Cash
Flow
Rapid volume growth expected in 2017, 2018 and beyond, driven by existing producers with
more than 514,000 dedicated acres on the system
Further potential upside from undedicated producers, AMI acreage and improved drilling
results / technology
Significant
Volume Growth
Potential to expand the system organically
Numerous bolt-on acquisition opportunities
Platform enhances ability to develop larger takeaway capacity projects
Growth
Platform for
NuStar
Fully integrated crude system centered around transportation, providing customers with
excellent access to multiple downstream end markets
Connection to nearly all destinations in Big Spring, Midland and Colorado City
Newly-built assets with minimal annual maintenance capex expected
Newly
Constructed/
Well Designed
System
16
1
1
2
5
6
10
13
13
16
23
23
47
0 25 50
Dawson
Ector
Borden
Gaines
Irion
Andrews
Glasscock
Reagan
Upton
Howard
Martin
Midland
Our Permian Crude System is in the Most
Active Areas of the Midland
Permian Basin has
379 rigs operating,
representing ~40% of
all U.S. onshore rig
activity
- 2.8x 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 as of 8/4/2017
Rigs by Top U.S. Play
Rigs by Permian
Sub-Basin
Rigs by Midland
Counties
Navigator Counties
17
15
29
30
45
46
53
60
78
379
0 200 400
Granite Wash
Utica
DJ-Niobrara
Haynesville
Marcellus
Bakken
Cana
Woodford
Eagle Ford
Permian
16
25
160
178
0 100 200
Other
Central
Basin
Platform
Midland
Delaware
Our Permian Crude System is an Integrated
Crude System
18
Permian Basin Continues to be the U.S. Basin
With the Strongest Growth
Rig counts in the Permian are up 275% (245% increase in the Midland) since the low in May 2016
Producers have realized lower break-evens due to multi-stack pay zones and improving well
productivity
Permian break-evens are estimated to be below $30 per barrel with current drilling and
completion costs
Most of our producers indicate they will continue at their current drilling pace at prices
above $40
Source: Wells Fargo Source: Baker Hughes 19
NuStar’s Permian Crude System Rig Counts
Much Higher than Initially Expected
Acquisition
Announcement
Current
July 31, 2017
Ship-or-pay Volume Commitments (Mbpd) 74,000 92,000
Dedicated Acreage 500,000 514,000
Dedicated Rig Count (actual) 28 39
Dedicated Rig Count (2017 forecast exit) 29
Dedicated Rig Count (2018 forecast exit)
38
Throughput Volumes (average monthly Mbpd) ~115,000 ~150,000
20
Permian Crude System Acquisition
Financing
The acquisition purchase price was funded by a combination of equity and debt offerings,
consistent with NuStar's targeted credit profile
Common Equity Offering
On April 18, NuStar issued 14.4 million new common units for gross proceeds of ~$665
million (including exercise of overallotment option)
Perpetual Preferred Offering
On April 28, we issued 15.4 million Series B perpetual preferred units for gross proceeds of
$385 million (including exercise of overallotment option)
Fixed distribution rate of 7.625% for five years
Thereafter, floating distribution rate of three-month LIBOR plus 5.643%, callable at
par after five years
21
Senior Notes Offering
On April 28, we raised $550 million by issuing 5.625% 10-year senior notes
due April 28, 2027
NuStar GP Holdings IDR Waiver
To demonstrate its strong support for the transaction, NuStar GP Holdings
agreed to temporarily forgo all IDR cash distributions to which it would be
entitled from any NuStar Energy L.P. common equity issuances after signing
the acquisition agreement:
For a period of ten (10) quarters from the date of the acquisition
closing (starting with the distribution for the 2nd quarter of 2017)
Capped at $22 million in the aggregate
Permian Crude System Acquisition
Financing (continued)
22
Permian Crude System Financial
Projections
Expect assets to contribute $30 to $50 million of EBITDA1 in 2017
Partially offset by $14 million of transaction related costs associated with closing the
acquisition
2018 EBITDA multiple expected to be in the low teens
EBITDA multiple expected to be in the high single digits by 2020
Growth capital spending projected to be ~$250 million over the next five years
~$123 million of spend forecasted to occur in 2017 on expansion of the system
Majority of 2017 spend related to expansion of transportation system and
gathering extensions
Currently there are 17 active construction projects, with a total of 28 more
in development
23 1 - Please see slides 36-40 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures
South Texas Crude Pipeline System Update
As expected, the Eagle Ford has seen a modest recovery, with rig counts up a significant 45
rigs from its low on July 29, 2016
Even with this recovery, pipeline capacity in the Eagle Ford currently exceeds production
and production is below aggregate minimum volume commitments
We have not seen volumes on our System increase, and we expect current utilization to
continue through 2018, due to shippers’ contract management strategies
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
25
South Texas Crude Pipeline
System Update
Return to Growth
$374 $302 $328 $288
$166
$380
to
$420
$316
$143
$96
$1,500
$0
$500
$1,000
$1,500
$2,000
2012 2013 2014 2015 2016 2017
Forecast
Internal Growth and Other Acquisitions
$262
TexStar
Acquisition
Expect $380 to $420 Million of Internal Growth
Spending in 2017 (Dollars in Millions)
2017 Total Capital Spending (excluding Navigator Acquisition price), which
includes Reliability Capital, is expected to be in the range of $415 to $475
million
2012 to 2017
Average Internal Growth
Spend $310 Million per Year
Linden JV
Acquisition
Martin
Terminal
Acquisition
Navigator
Acquisition
27
$690
$431
Several projects have been completed or under development to increase distillate and
propane supply throughout the Upper Midwest for an investment of approximately $80 million
Propane supply projects complete and in service
Construction on remaining projects should be completed by the fourth quarter of 2017
Mid-Continent
Pipeline &
Terminals
Effective in the first quarter of 2017, recontracted 9.5 million barrels of storage
Approximately $100 million of facility enhancements with expected completion in 2017
St. Eustatius
Terminal
Purchased 1.15 mmbbls of crude and refined products storage for $93mm, net
Assets located adjacent to existing NuStar Corpus Christi North Beach Terminal
Completion of Port of Corpus Christi’s new state-of-the-art dock in 2H 2017 will allow for
increased volumes
Corpus Christi
Terminal
Acquisition
Purchased for ~$1.5 billion
Growth capital spending projected to be ~$250 million over the next five years
~$123 million of spend to occur in 2017 on expansion of the system
Permian Crude
System
Expansion
Base Business Projects and
Growth Opportunities – Included in 2017 Guidance
Linden Terminal
Constructing 500MBbls of new storage in the New York Harbor
Expected cost of ~$50 million in 2017
Expect to complete construction in the first quarter of 2018
28
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 $1.5 Billion
Opportunities to expand Northeast operations
Additional tankage at our St. James Terminal
Renewable opportunities on the East and West Coast
29
Additional Permian Takeaway Capacity Still
Needed
Even with many completions delayed, the Permian
Basin is on track to add 540 MBPD over the course of
this year
Several new infrastructure projects have been
announced recently to handle the expected production
Given long-term production curve and
assuming these new projects come to
fruition, we still believe that there is
room for another long-haul pipeline
from Permian to Corpus
In addition to working with shippers on
our own long-haul project, we are
currently in discussions with potential
strategic partners to combine and
construct assets for this long-haul
solution
Source: Rystad Energy
Expanded System Owner Expansion Volume
BridgeTex Magellan/Plains 40M Bbl/d
Cactus Plains 60M Bbl/d
Midland to Sealy Enterprise 450M Bbl/d
Permian Express III unoco 200M Bbl/d
30 Source: Rystad Energy, ESAI, and EIA
Finance Update
No Debt Maturities until 2018
($ in Millions)
Callable in 2018, but
final maturity in 2043
32
$765
$350
$450
$300 $250
$550
$365
$403
$53
$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
$806
Note: Debt maturities as of 6/30/17
2017 Guidance Summary
($ in Millions)
Annual EBITDA1
G&A
Expenses
Reliability Capital
Spending
Strategic Capital
Spending
Previous Guidance $620 - $670 $100 - $120 $35 - $55 $400 - $440
Delayed volume ramp on Permian Crude
System, lower than expected vessel
activity at St. Eustatius and impact of
increased customer turnaround activity
($20)
Additional expansion on the Permian
Crude System, more than offset by
deferred strategic project spending,
primarily on northern Mexico supply
project
($20)
Current Guidance $600 - $650 $100 - $120 $35 - $55 $380 - $420
1 - Please see slides 36-40 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures 33
Note: No changes to the guidance provided on the second quarter earnings conference call, held on July 28, 2017
Appendix
Capital Structure
($ in Millions)
As of June 30, 2017
(Unaudited)
$1.5 billion Credit Facility $765
NuStar Logistics Notes (4.75%) 250
NuStar Logistics Notes (4.80%) 450
NuStar Logistics Notes (5.63%) 550
NuStar Logistics Notes (6.75%) 300
NuStar Logistics Notes (7.65%) 350
NuStar Logistics Sub Notes (7.63%) 403
GO Zone Bonds 365
Receivables Financing 53
Short-term Debt & Other 36
Total Debt $3,522
Total Partners’ Equity 2,501
Total Capitalization $6,023
Availability under $1.5 billion Credit Facility (as of June 30, 2017): ~$727 million
Debt to EBITDA1 calculation per Credit Facility of 4.6x (as of June 30, 2017)
1 – Please see slides 36-40 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures 35
Reconciliation of Non-GAAP
Financial Information
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.
36
Reconciliation of Non-GAAP
Financial Information (continued)
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,
37
Reconciliation of Non-GAAP
Financial Information (continued)
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
38
Reconciliation of Non-GAAP
Financial Information (continued)
For the Quarter Ended
Sept. 30, 2014 Dec. 31, 2014 Mar. 31, 2015 Jun. 30, 2015 Sept. 30, 2015 Dec. 31, 2015 Mar. 31, 2016 Jun. 30, 2016 Sept. 30, 2016 Dec. 31, 2016 Mar. 31, 2017 Jun. 30, 2017
(Loss) income from continuing operations (116,202)$ 214,169$ 298,298$ 295,436$ 301,335$ 305,946$ 236,222$ 234,414$ 220,539$ 150,003$ 150,542$ 26,250$
Interest expense, net 132,208 131,226 129,901 129,603 130,044 131,868 133,954 135,359 136,933 138,350 140,641 45,612
Income tax expense 14,983 10,801 9,071 10,310 10,281 14,712 15,195 16,361 14,208 11,973 12,028 1,630
Depreciation and amortization expense 188,570 191,708 197,935 202,764 206,466 210,210 210,895 211,781 213,426 216,736 220,458 67,601
EBITDA from continuing operations 219,559$ 547,904$ 635,205$ 638,113$ 648,126$ 662,736$ 596,266$ 597,915$ 585,106$ 517,062$ 523,669$ 141,093$
Equity in losses (earnings) of joint ventures 11,604 (4,796) (9,102) (5,808) (3,059) - - - - - - -
Interest expense, net (132,208) (131,226) (129,901) (129,603) (130,044) (131,868) (133,954) (135,359) (136,933) (138,350) (140,641) (45,612)
Reliability capital expenditures (29,862) (28,635) (30,674) (29,464) (32,439) (40,002) (39,221) (44,497) (43,770) (38,155) (37,160) (10,380)
Income tax expense (14,983) (10,801) (9,071) (10,310) (10,281) (14,712) (15,195) (16,361) (14,208) (11,973) (12,028) (1,630)
Distributions from joint venture 8,048 7,587 7,721 6,993 4,208 2,500 - - - - - -
Mark-to-market impact of hedge transactions (a) (90) 6,125 4,991 (261) (132) (5,651) 152 4,474 5,372 10,317 3,047 (563)
Unit-based compensation (b) - - - - - - 1,086 2,208 3,499 5,619 6,621 1,618
Other items (c) 323,764 19,732 (34,471) (36,351) (41,628) (44,032) 10,110 11,518 19,185 73,846 74,075 (1,095)
Preferred unit distributions - - - - - - - - - (1,925) (6,738) (9,950)
DCF from continuing operations 385,832$ 405,890$ 434,698$ 433,309$ 434,751$ 428,971$ 419,244$ 419,898$ 418,251$ 416,441$ 410,845$ 73,481$
Less DCF from continuing operations available
to general partner 51,064 51,064 51,064 51,064 51,064 51,064 51,064 51,064 51,164 51,284 51,417 (d) 13,214
DCF from continuing operations available
to common limited partners 334,768$ 354,826$ 383,634$ 382,245$ 383,687$ 377,907$ 368,180$ 368,834$ 367,087$ 365,157$ 359,428$ (d) 60,267$
Distributions applicable to common limited partners 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ 341,798$ 342,598$ 343,485$ (d) 101,869$
Distribution coverage ratio (e) 0.98x 1.04x 1.12x 1.12x 1.12x 1.11x 1.08x 1.08x 1.07x 1.07x 1.05x (d) 0.59x
(a)
(b)
(c)
(d) For the three months ended March 31, 2017, amounts adjusted to exclude distributions that were paid on the 14,375,000 common units that were issued April 18, 2017.
(e) Distribution coverage ratio is calculated by dividing DCF from continuing operations available to common limited partners by distributions applicable to common limited partners.
The following is a reconciliation of (loss) income from continuing operations to EBITDA from continuing operations and DCF from continuing operations (in thousands of dollars, except ratio data):
For the Twelve Months Ended
DCF from continuing operations excludes the impact of 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 DCF from continuing operations when the contracts are settled.
In connection with the employee transfer from NuStar GP, LLC on March 1, 2016, we assumed obligations related to awards issued under a long-term incentive plan, and we intend to satisfy the vestings of equity-based awards with the
issuance of our units. As such, the expenses related to these awards are considered non-cash and added back to DCF. Certain awards include distribution equivalent rights (DERs). Payments made in connection with DERs are
deducted from DCF.
Other items mainly consist of (i) adjustments for throughput deficiency payments and construction reimbursements for all periods presented, (ii) a $58.7 million non-cash impairment charge on the Axeon term loan in the fourth quarter of
2016, (iii) a $56.3 million non-cash gain associated with the Linden terminal acquisition in the first quarter of 2015 and (iv) a non-cash goodwill impairment charge totaling $304.5 million in the fourth quarter of 2013.
39
Reconciliation of Non-GAAP
Financial Information (continued)
The following are reconciliations of projected net income to projected EBITDA (in thousands of dollars):
Current Guidance Previous Guidance *
Projected net income $ 160,000 - 190,000 $ 175,000 - 190,000
Projected interest expense, net 170,000 - 175,000 175,000 - 185,000
Projected income tax expense 10,000 - 15,000 10,000 - 15,000
Projected depreciation and amortization expense 260,000 - 270,000 260,000 - 280,000
Projected EBITDA $ 600,000 - 650,000 $ 620,000 - 670,000
The following is a reconciliation of projected operating income to projected EBITDA for the Permian Crude System (in thousands of dollars):
Year Ended
December 31, 2017
Projected operating income $ 5,000 - 10,000
Projected depreciation and amortization expense 25,000 - 40,000
Projected EBITDA $ 30,000 - 50,000
For the Four Quarters Ended
June 30, 2017
Net income 124,275$
Interest expense, net 152,024
Income tax expense 9,388
Depreciation and amortization expense 234,408
EBITDA 520,095
Other expense (a) 58,183
Equity awards (b) 9,827
Mark-to-market impact on hedge transactions (c) (3,278)
Pro forma effect of acquisitions (d) 78,825
Material project adjustments (e) 10,213
Consolidated EBITDA, as defined in the Revolving Credit Agreement 673,865$
Total consolidated debt 3,531,061$
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 3,087,085$
Consolidated Debt Coverage Ratio (Consolidated Debt to Consolidated EBITDA) 4.6x
(a)
(b)
(c)
(d)
(e)
* Guidance presented at the 2017 MLP Investor Conference.
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 $1.5 billion five-year
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.
Year Ended December 31, 2017
40