8-K

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, 2016

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:

oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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 2016 Wells Fargo Securities Energy Symposium in New York City on December 6, 2016. 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 on the “Investors” section of the Partnership’s website at www.nustarenergy.com at 8:00 a.m. (Eastern Time) on December 6, 2016.

Item 9.01    Financial Statements and Exhibits.

(d)     Exhibits.

Exhibit Number	Exhibit
Exhibit 99.1	Slides to be used on December 6, 2016.

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: December 6, 2016			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 to be used on December 6, 2016.

4

EX-99.1

Wells Fargo Securities - 2016 Energy Symposium December 6, 2016 Exhibit 99.1

Forward-Looking Statements 2 Statements contained in this presentation that state management’s expectations or predictions of the future 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 almost always vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance 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 G.P. Interest in NS IPO Date: 4/16/2001 ~13% Common L.P. Interest in NS Common Unit Price (12/2/16): $48.02 Incentive Distribution Rights in NS (IDR) Annualized Distribution/Common Unit: $4.38 ~13% NS Distribution Take Yield (12/2/16): 9.1% IPO Date: 7/19/2006 Market Capitalization: $3.8 billion Unit Price (12/2/16): $26.55 Enterprise Value: $6.9 billion Annualized Distribution/Unit: $2.18 Credit Ratings Yield (12/2/16): 8.2% Moody's: Ba1/Stable Market Capitalization: $1.1 billion S&P: BB+/Stable Enterprise Value: $1.2 billion Fitch: BB/Stable NYSE: NSH NYSE: NS William E. Greehey 9.0 million NSH Units 21.0% Membership Interest Public Unitholders 68 million Common 8 million Preferred Public Unitholders 33.9 million NSH Units 79.0% Membership Interest

Large and Diverse Geographic Footprint with Assets in Key Locations Assets:  79 terminals  ~94 million barrels of storage capacity  ~8,700 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 5

… and in 2016 (through 12/2/16) YTD Returns  NuStar Energy L.P. 32.6%  NuStar GP Holdings, LLC 38.9%  Alerian MLP Index 11.7%  S&P 500 9.5% NuStar Has Outperformed the Alerian Since the Beginning of the Crude Downturn… 6 -80% -60% -40% -20% 0% 20% Jun-14 Oct-14 Mar-15 Aug-15 Jan-16 Jun-16 Nov-16 NS AMZ Crude (% change) Total Return as of 12/2/16

Our 2016 Accomplishments in the Face of Challenges  We have succeeded this year by leveraging our strengths  Diverse assets: type (pipelines and terminals), market (refined products and crude) and geography  Disciplined financial management  Operational excellence  Efficient project management  In 2016, we:  Expect to deploy $253 to $273 million of strategic capital  Re-contracted 9.5MMBbls in St. Eustatius at higher rates  Reactivated 2.5MMBbls of products storage in Piney Point  Implemented new At-the-Market (ATM) unit issuance program  Issued $200 million of 8.50% Series A fixed-to-floating rate cumulative redeemable perpetual preferred units  Signed an asset purchase agreement to purchase terminals with 1.2MMBbls of storage and associated dock assets  Continued to be ranked as one of the best places to work by Fortune magazine  Our continued strong distribution coverage and solid earnings, even in the face of an industry downturn of historic proportions, demonstrates the resiliency and strength of our business model and our strategic direction 7

Resilient and Strong Core Operations, No Matter the Price of a Barrel of Crude 8 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 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  Although valuations of some MLPs have de-coupled from crude prices – we still believe that our valuation does not yet reflect our solid financial results, stable cash flow and overall stability and strength of our business  Total unitholder return since recent low on January 20, 2016 +101%2, however still down -16%2 from last year’s high on April 30, 2015. Coverage Ratio1 (Trailing Twelve Months) vs Price of Crude (July 2014 – September 2016) 2 – Total unitholder returns as of December 2, 2016. 1.07x 0.98x 1.04x 1.12x 1.12x 1.11x 1.08x 1.12x 1.08x 3Q-16 3Q-14 4Q-14 1Q-15 2Q-15 3Q-15 4Q-15 1Q-16 2Q-16 1 – Please see slides 32-34 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measure

Percentage of Expected 2016 Annual Segment EBITDA  Refined Product Pipelines  Crude Oil Pipelines  Ammonia Pipeline  Refined Product Terminals  Crude Oil Storage Fuels Marketing: 2%  Refined Products Marketing, Bunkering and Crude & Fuel Oil Trading Majority of Segment EBITDA Generated by Fee-Based Pipeline and Storage Segments  Pipeline and Storage segments expected to account for about 98% of 2016 annual segment EBITDA Storage: 49% Pipeline: 49% 9 49% 49%

Guidance Summary 10 2016 Annual Guidance (3Q Earnings Call1) 4th Quarter 2016 Guidance (3Q Earnings Call1) 2017 Annual Guidance (3Q Earnings Call1) Pipeline Segment EBITDA2 $325 - $345 million Lower than 4Q 2015 Storage Segment EBITDA2 $330 - $350 million Lower than 4Q 2015 Fuels Marketing Segment EBITDA2 $5 - $10 million Slightly higher than 4Q15 Annual EBITDA2 $600 - $650 million General and Administrative Expenses $100 - $110 million Reliability Capital Spending $35 - $45 million $35 - $55 million Strategic Capital Spending $160 - $180 million internal growth plus net $93 million for Martin Acquisition $530 - $550 million Earnings Per Unit $0.50 - $0.60 per unit 1 - Third quarter 2016 earnings call was held on November 2, 2016 (related materials and non-GAAP information are available on our website at nustarenergy.com) 2 - Please see slides 32-34 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures

11 Building on Our Strengths - Stable, Diversified Business Foundation for Future Growth  Contracted fee-based storage and pipeline assets provide stable cash flows  Storage terminals effectively full  ~75% of pipeline revenues are demand-pull - based on refinery/fertilizer plant feedstock supply or refinery production delivery  ~25% of pipeline revenues are Eagle Ford volumes to area refineries or Corpus Christi, TX docks  ~95% of tariffs are FERC-based, which are adjusted annually for inflation  Diverse and high-quality customer base composed of large integrated oil companies, national oil companies and refiners 1 – ~95% committed through take or pay contracts or through structural exclusivity (uncommitted lines serving refinery customers with no competition) Storage Lease Utilization ~95% of Leasable Storage Effectively Full Pipeline Revenue – Contract1 % ~95% Committe d1

TexStar Acquisition On Track for $253 to $273 Million of Strategic Spending in 2016 and Expect $530 to $550 Million of Strategic Spending in 2017 (Dollars in Millions) $374 $302 $328 $288 $160 to $180 $530 to $550 $316 $143 $93 $0 $100 $200 $300 $400 $500 $600 $700 $800 2012 2013 2014 2015 2016 Forecast 2017 Forecast Internal Growth and Other Acquisitions $253 to $273  2016 Total Capital Spending, which includes Reliability Capital, is expected to be in the range of $288 to $318 million  2017 Total Capital Spending, which includes Reliability Capital, is expected to be in the range of $565 to $605 million 12 2012 to 2016 Average Internal Growth Spend $334 Million per Year Linden JV Acquisition Martin Terminal Acquisition $690 $431

Pursuing Pipeline and Storage Opportunities 3.8MM bbls 13 Expansion of Ammonia Pipeline System Included in 2016 & 2017 Spending Guidance Currently Evaluating West Coast Terminal Expansions Construction of ~750M bbls of New Storage at St. James Linden Terminal Expansion Project to Transport LPGs and Refined Products from the U.S. into Northern Mexico Expansion of our South Texas Crude Oil & Refined Product Pipeline Systems Strategic Growth Opportunities: - $1.0 to $1.5 billion1 - Focused on developing synergistic, high-return projects 1 – capital spending time horizon is next one to three years. Construction of ~260M bbls of New Storage in the Central East Further Expansion of our St. James Terminal Terminal Expansion Opportunities in the Northeast St. Eustatius Optimization Project

No Debt Maturities until 2018 (LTD Maturity Profile as of September 30, 2016, Dollars in Millions)  Long-term Debt structure 55% fixed rate – 45% variable rate Callable in 2018, but final maturity in 2043 14 $992 $350 $450 $300 $250 $365 $403 $43 $0 $250 $500 $750 $1,000 $1,250 2015 2016 2017 2018 2019 2020 2021 2022 2038- 2041 Receivables Financing Sub Notes GO Zone Financing Senior Unsecured Notes Revolver $796

NuStar Energy Recently Issued $200 Million of Perpetual Preferred Equity 15  On November 25, 2016, NuStar Energy issued 8 million 8.50% Series A Fixed-to- Floating Rate Cumulative Redeemable Perpetual Preferred Units at a price of $25 per unit  Net proceeds of approximately $193 million were received after paying offering related expenses  Underwriters have been granted a 30-day option to purchase up to an additional 1.2 million units  Units are callable at $25 par value on or after December 15, 2021  During non-call period the coupon on units is fixed at 8.50%  On December 15, 2021 the coupon converts to a floating rate of three-month LIBOR plus 6.77%  Issuance recorded as equity on NuStar’s balance sheet  Receives 100% equity credit from Moody’s and 50% equity credit from S&P and Fitch  Coupon/cost associated with preferred equity is significantly lower than the cost of issuing NuStar common equity in today’s market  All-in cost associated with NuStar common equity on November 17, 2016 was around 12%  Annual savings of approximately $7 million realized by issuing preferred versus common equity

Pipeline Segment

17  2016 segment EBITDA should be lower than 2015 as we expect increased volumes on our refined product pipelines to be offset by lower projected Eagle Ford crude volumes. Pipeline Segment Overview Pipeline Segment EBITDA1 ($ in millions) Pipeline Receipts by Commodity TTM as of 9/30/16 *Other includes ammonia, jet fuel, propane, naphtha and light-end refined products 1 – Please see slides 32-34 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures $186 $190 $199 $198 $211 $277 $323 $355 $325 to $345 2008 2009 2010 2011 2012 2013 2014 2015 2016 Forecast Crude 42% Gasoline 31% Distillate 17% Other 10%

Throughputs in NuStar’s South Texas Crude Oil Pipeline System 18 South Texas Crude Oil Pipeline System:  2016 and 2017 guidance at contractual minimums (133.5 Mbpd), upside potential with a crude oil price recovery  For 2016, we expect to receive revenues in excess of actual shipped throughput volumes  Throughput and deficiency agreements with strong, credit-worthy, investment grade customers  Earliest renewal in 3Q 2018 (2-7 years remaining on all contracts) 168 179 218 255 270 290 272 263 238 207 190 188 112 120 149 173 179 190 193 175 161 131 131 133 100 200 300 4Q 2013 Actual 1Q 2014 Actual (Corpus Dock) 2Q 2014 Actual (Phase 1) 3Q 2014 Actual 4Q 2014 Actual 1Q 2015 Actual (Phase 2) 2Q 2015 Actual 3Q 2015 Actual 4Q 2015 Actual 1Q 2016 Actual 2Q 2016 Actual 2016 and 2017 Estimates Total Eagle Ford Throughputs - Avg. Daily Throughputs (MBPD), Includes South Texas Crude Oil Pipeline System Throughputs South Texas Crude Oil Pipeline System Throughputs into our Corpus Christi North Beach Terminal - Avg. Daily Throughputs (MBPD) 2016 and 2017 aaEstimates

NuStar’s South Texas Pipeline Presence 19 Choke Canyon PL – 12” Pettus South – 10” Pawnee to Oakville PL – 12” Three Rivers Supply – 12” Corpus-Odem-3R – 8” Oakville to Corpus – 16” Second Phase of Expansion – 12”

Working with Pemex to Develop Project to Transport LPGs and Refined Products from the U.S. Into Northern Mexico 20  Delays due to organizational changes within Pemex  Originally planned $125 million spend in 2016. Due to project delay, spending to take place in 2017 and 2018

NuStar Expanding Mid-Continent Pipeline and Terminal Network  Several projects have been completed or are under development with a key customer to increase distillate and propane supply throughout the Upper Midwest for an investment of approximately $80 million  Capital investments to be backed by long- term agreements  Propane supply projects complete and in service  Construction on remaining projects should be completed by the fourth quarter of 2017 21

Storage Segment

 2016 segment EBITDA expected to benefit from higher renewal rates and increased utilization, which may be partially offset by lower expected Eagle Ford throughput volumes into our Corpus Christi North Beach Terminal as a result of decreased Eagle Ford shale production  2017 storage results expected to benefit from higher renewal rates recently negotiated at some of our terminals and the upcoming Martin terminal acquisition 1 – Please see slides 32-34 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures Storage Segment EBITDA1 ($ in millions) 23 Storage Segment Overview * * adjusted $208 $242 $256 $279 $287 $277 $287 $335 $330 to $350 2008 2009 2010 2011 2012 2013 2014 2015 2016 Forecast

24 Building Our Strategic Alliances in Europe For Future Growth  As the European market changes, we continue to expand on strategic alliances with our current customers to drive growth through:  Working on a long-term agreement with customer at Grays to provide terminaling for all of their Southeast England throughput  The agreement will require facility upgrades including enhanced jetty capabilities, a vapor recovery unit and pipeline upgrades  Developing alliance with a customer for larger throughput position at Eastham and Grays  Discussions continue to increase customer’s fuel business in Grays  Exploring opportunities to take advantage of a customer’s recent refinery acquisition in Southern Ireland, which will increase the supply of gasoline necessary to blend and distribute out of Amsterdam  We are working with a customer to manage their gasoline blending program and throughputs  We should be able to solidify our customer’s position in our terminal and allow us to use for a growth platform Clydebank Belfast Eastham Runcorn Grays Amsterdam Grangemouth Netherlands United Kingdom

25  Acquiring control of the Linden Terminal in 2015 has freed us to develop opportunities that will increase our capability to serve the New York Harbor (NYH), which is one of the largest trading hubs of refined product in the world  NYH storage demand continues to be strong and our terminal has been 100% utilized for over 12 years with the exception of periods for inspections and maintenance  We continue to receive inquires for storage, but due to an approximately 18-month permitting and construction process, it is difficult to secure customer commitments so far in advance  Currently, we plan to construct 500MBbls of new storage at a cost of about $50 million (included in 2017 spending guidance provided) We Are Exploring Expansion in the New York Harbor

 Piney Point Terminal  5.4 million-barrel storage facility located in Piney Point, Maryland, along the Potomac River  Primary storage capabilities include gasoline, distillates and other clean products  Reactivated due to favorable market economics  Signed up storage commitments for 2.5 million barrels  Contract allows customer to take advantage of the contango market structure  First delivery of 189,000 barrels of ULSD arrived on April 21, 2016  2.5 million barrels (above) includes additional 650,000 barrels effective January 2017 26 Piney Point Terminal Back in Service

27 Majority of St. Eustatius Terminal Tankage Recently Leased through 1st Quarter of 2020  St. Eustatius Terminal  14.4 million-barrel storage facility located on the island of St. Eustatius in the Caribbean  Primary storage capabilities include crude oil and fuel oil (as well as other refined products)  Can accommodate ULCCs (ultra large crude carriers)  Recently re-contracted 9.5 million barrels of storage  Contract renewal (and additional leased barrels) effective in first quarter 2017, with a three-year lease term  Favorable renewal rates achieved due to current market conditions  Expect to spend approximately $100 million on facility enhancements; strategic capital spending to take place in 2016 and 2017 27

We Are Adapting to Market Flows: Renewables Opportunities on the West Coast  The West Coast: In a mature fuel supply market, biofuels provide opportunities for growth  Low carbon initiatives on the West Coast (e.g. California’s Low Carbon Fuel Standard) promote the use of biofuels  We currently offer ethanol storage and blending at Selby, Stockton, Portland and Tacoma  We are pursuing projects to expand ethanol export capabilities at Stockton and add ethanol blending in Vancouver  Projects in development to add or expand biodiesel and/or renewable diesel at Stockton, Selby, Portland and Tacoma 28

29  Martin Midstream terminal assets  1.15 million barrels of storage (900,000 barrels of crude and 250,000 barrels of refined product storage), located in Corpus Christi, Texas  Terminals have direct connectivity to Eagle Ford production through connection to the Harvest Pipeline, a six-bay truck rack and access to two deep-water crude oil docks  Terminals located on 25 acres with expansion opportunities  Synergies and Economics  Terminals and docks located adjacent to our existing Corpus Christi North Beach Terminal  Minimum volume contract in place through November 2017  Expect a positive renewal outcome with existing customer, which is a current NuStar customer in Corpus Christi  Construction on Martin’s new state-of-the-art dock (which will be adjacent to our own existing docks upon completion) is expected to be completed early in the second half of 2017  Allows us to forego building our own dock at a major cost savings  New dock will provide capability for larger vessels and increased volumes  Scheduling synergies with our existing docks  We have agreed to pay $93 million, net for these assets, generating a seven-times EBITDA multiple based on an annual average EBITDA1 estimate of ~$13.5 million  Expect to close on this acquisition by the end of 2016 Recently Announced Corpus Christi Terminal Acquisition from Martin Midstream 1 – Please see slides 32-34 for explanation of non-GAAP financial measures

Appendix

Capital Structure after Perpetual Preferred Equity Issuance ($ in Millions) As of September 30, 2016 Actual As Adjusted (Unaudited) $1.5 billion Credit Facility $992 $799 NuStar Logistics Notes (4.75%) 250 250 NuStar Logistics Notes (4.80%) 450 450 NuStar Logistics Notes (6.75%) 300 300 NuStar Logistics Notes (7.65%) 350 350 NuStar Logistics Sub Notes (7.625%) 403 403 GO Zone Bonds 365 365 Receivables Financing 43 43 Short-term Debt 7 7 Total Debt $3,160 $2,967 Total Partners’ Equity 1,470 1,663 Total Capitalization $4,630 $4,630  Availability under $1.5 billion Credit Facility (as of September 30, 2016): ~$492 million  $992 million in borrowings and $16 million in Letters of Credit outstanding  Debt to EBITDA1 calculation per Credit Facility of 4.6x (as of September 30, 2016)  Net proceeds of $193 million from the perpetual preferred equity issuance were used to reduce the $1.5 billion Credit Facility balance in the “As Adjusted” column 31 1 – Please see slides 32-34 for reconciliations of non-GAAP financial measures to their most directly comparable GAAP measures

Reconciliation of Non-GAAP Financial Information 32 2008 2009 2010 2011 2012 2013 2014 2015 Operating income 135,086$ 139,869$ 148,571$ 146,403$ 158,590$ 208,293$ 245,233$ 270,349$ Plus depreciation and amortization expense 50,749 50,528 50,617 51,165 52,878 68,871 77,691 84,951 EBITDA 185,835$ 190,397$ 199,188$ 197,568$ 211,468$ 277,164$ 322,924$ 355,300$ 2008 2009 2010 2011 2012 2013 2014 2015 Operating income (loss) 141,079$ 171,245$ 178,947$ 196,508$ 198,842$ (127,484)$ 183,104$ 217,818$ Plus depreciation and amortization expense 66,706 70,888 77,071 82,921 88,217 99,868 103,848 116,768 EBITDA 207,785$ 242,133$ 256,018$ 279,429$ 287,059$ (27,616)$ 286,952$ 334,586$ Impact from non-cash goodwill impairment charges 304,453 Adjusted EBITDA 276,837$ The following is a reconciliation of operating income to EBITDA for the pipeline 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, This presentation includes forecasted EBITDA for assets we expect to acquire from Martin Midstream Partners L.P. This is a non-GAAP financial measure. Forecasted EBITDA is based on the partnership’s projections for the assets to be acquired. Forecasted EBITDA is included to help facilitate comparisons of operating performance of the partnership with other companies in our industry, as well as help facilitate an assessment of our assets' projected ability to generate sufficient cash flow to make distributions to our partners. We are unable to present a reconciliation of forecasted EBITDA to net income because certain elements of net income, including interest, depreciation and taxes, are not available. Together, these items generally result in EBITDA being significantly greater than net income. 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 reconciliations exclude any allocation of general and administrative expenses consistent with our policy for determining segmental operating income, the most directly comparable GAAP measure. 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 and (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. 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 the metric for determining the company-wide bonus and the vesting of performance units awarded to management as our board of directors believes DCF appropriately aligns management’s interest with our unitholders’ interest in increasing distributions in a prudent manner. 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.

Reconciliation of Non-GAAP Financial Information (continued) 33 Pipeline Segment Storage Segment Fuels Marketing Segment Projected operating income $ 240,000 - 255,000 $ 215,000 - 230,000 $ 5,000 - 10,000 Plus projected depreciation and amortization expense 85,000 - 90,000 115,000 - 120,000 - Projected EBITDA $ 325,000 - 345,000 $ 330,000 - 350,000 $ 5,000 - 10,000 The following is a reconciliation of projected net income to projected EBITDA (in thousands of dollars): Year Ended December 31, 2017 Projected net income $ 200,000 - 230,000 Projected interest expense, net 160,000 - 165,000 Projected income tax expense 10,000 - 15,000 Projected depreciation and amortization expense 230,000 - 240,000 Projected EBITDA $ 600,000 - 650,000 September 30, 2016 Net income 220,539$ Interest expense, net 136,933 Income tax expense 14,208 Depreciation and amortization expense 213,426 EBITDA 585,106 Other expense 80 Mark-to-market impact on hedge transactions (a) 5,372 Material project adjustments (b) 5,890 Consolidated EBITDA, as defined in the Revolving Credit Agreement 596,448$ Total consolidated debt 3,160,386$ NuStar Logistics' 7.625% fixed-to-floating rate subordinated notes (402,500) Proceeds held in escrow associated with the Gulf Opportunity Zone Revenue Bonds (41,922) Consolidated Debt, as defined in the Revolving Credit Agreement 2,715,964$ C nsolidated Debt Coverage Ratio (Consolidated Debt to Consolidated EBITDA) 4.6x (a) (b) 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. The following is a reconciliation of projected operating income to projected EBITDA for the year ended December 31, 2016 (in thousands of dollars): 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): For the Four Quarters Ended 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.

Reconciliation of Non-GAAP Financial Information (continued) 34 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 Income from continuing operations (116,202)$ 214,169$ 298,298$ 295,436$ 301,335$ 305,946$ 236,222$ 234,414$ 220,539$ Interest expense, net 132,208 131,226 129,901 129,603 130,044 131,868 133,954 135,359 136,933 Income tax expense 14,983 10,801 9,071 10,310 10,281 14,712 15,195 16,361 14,208 Depreciation and amortization expense 188,570 191,708 197,935 202,764 206,466 210,210 210,895 211,781 213,426 EBITDA from continuing operations 219,559$ 547,904$ 635,205$ 638,113$ 648,126$ 662,736$ 596,266$ 597,915$ 585,106$ 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) Reliability capital expenditures (29,862) (28,635) (30,674) (29,464) (32,439) (40,002) (39,221) (44,497) (43,770) Income tax expense (14,983) (10,801) (9,071) (10,310) (10,281) (14,712) (15,195) (16,361) (14,208) 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 Unit-based compensation (b) - - - - - - 1,086 2,208 3,499 Other items (c) 323,764 19,732 (34,471) (36,351) (41,628) (44,032) 10,110 11,518 19,185 DCF from continuing operations 385,832$ 405,890$ 434,698$ 433,309$ 434,751$ 428,971$ 419,244$ 419,898$ 418,251$ 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 DCF from continuing operations available to limited partners 334,768$ 354,826$ 383,634$ 382,245$ 383,687$ 377,907$ 368,180$ 368,834$ 367,087$ Distributions applicable to limited partners 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ 341,140$ 341,798$ Distribution coverage ratio (d) 0.98x 1.04x 1.12x 1.12x 1.12x 1.11x 1.08x 1.08x 1.07x (a) (b) (c) (d) Distribution coverage ratio is calculated by dividing DCF from continuing operations available to limited partners by distributions applicable to limited partners. The following is a reconciliation of 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-classified 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 $56.3 million non-cash gain associated with the Linden terminal acquisition on January 2, 2015 included in other income in our statements of income and (iii) a non-cash goodwill impairment charge totaling $304.5 million in the fourth quarter of 2013.