SEC Filing | NuStar Energy L.P.

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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): December 6, 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 Wells Fargo 2017 Pipeline, MLP and Utility Symposium in New York City on December 6, 2017. The slides attached to this report were prepared in connection with, and are being used during, the symposium. 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 8:00 a.m. (Eastern Time) on December 6, 2017.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits.



Exhibit Number		Exhibit

Exhibit 99.1		Slides to be used on December 6, 2017.

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: December 6, 2017			By:	/s/ Amy L. Perry
			Name:	Amy L. Perry
			Title:	Senior Vice President, General Counsel - Corporate & Commercial Law and Corporate Secretary

nsexhibit991wf120617

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.