News Column

HOLLY ENERGY PARTNERS LP - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations

February 24, 2014

This Item 7, including but not limited to the sections on "Liquidity and Capital Resources," contains forward-looking statements. See "Forward-Looking Statements" at the beginning of Part I and Item 1A. "Risk Factors." In this document, the words "we," "our," "ours" and "us" refer to HEP and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person.

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OVERVIEW

HEP is a Delaware limited partnership. We own and operate petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities that support HFC's refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Alon's refinery in Big Spring, Texas. At December 31, 2013, HFC owned a 39% interest in us including the 2% general partnership interest. Additionally, we own a 75% interest in UNEV, the owner of a pipeline running from Woods Cross, Utah to Las Vegas, Nevada and related products terminals and a 25% joint venture interest in the SLC Pipeline, a 95-mile intrastate crude oil pipeline system that serves refineries in the Salt Lake City, Utah area.

We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling and storing refined products and other hydrocarbons and providing other services at our storage tanks and terminals. We do not take ownership of products that we transport, terminal or store, and therefore we are not directly exposed to changes in commodity prices.

On January 16, 2013, a two-for-one unit split was paid in the form of a common unit distribution for each issued and outstanding common unit to all unitholders of record on January 7, 2013. All references to unit and per unit amounts in this document and related disclosures have been adjusted to reflect the effect of the unit split for all prior periods presented.

In March 2013, we closed on a public offering of 1,875,000 of our common units. Additionally, an affiliate of HFC, as a selling unitholder, closed on a public sale of 1,875,000 of its HEP common units for which we did not receive any proceeds. We used our net proceeds of $73.4 million to repay indebtedness incurred under our credit facility and for general partnership purposes. Amounts repaid under our credit facility may be reborrowed from time to time, and we intend to reborrow certain amounts to fund capital expenditures.

We believe the continuing growth of crude production in the Permian Basin and throughout the Mid-Continent and favorable refining economics should support high utilization rates for the refineries we serve, which in turn will support volumes in our product pipelines, crude gathering system and terminals.

UNEV Pipeline Interest Acquisition On July 12, 2012, we acquired HFC's 75% interest in UNEV. We paid consideration consisting of $260.9 million in cash and 2,059,800 of our common units. Also under the terms of the transaction, we issued to HFC a Class B unit comprising a noncontrolling equity interest in a wholly-owned subsidiary subject to redemption to the extent that HFC is entitled to a 50% interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2016 and ending in June 2032, subject to certain limitations. However, to the extent earnings thresholds are not achieved, no redemption payments are required. Contemporaneously with this transaction, HFC (our general partner) agreed to forego its right to incentive distributions of up to $1.25 million per quarter over twelve consecutive quarterly periods following the closing of the transaction and up to an additional four quarters in certain circumstances. In connection with the transaction, we entered into 15-year throughput agreements with shippers containing minimum annual revenue commitments to us of $25 million.

Legacy Frontier Pipeline and Tankage Asset Transaction On November 9, 2011, we acquired from HFC certain tankage, loading rack and crude receiving assets located at HFC's El Dorado and Cheyenne refineries. We paid non-cash consideration consisting of promissory notes with an aggregate principal amount of $150 million and 7,615,230 of our common units. In connection with the transaction, we entered into 15-year throughput agreements with HFC containing minimum annual revenue commitments to us of $48.3 million.

Agreements with HFC and Alon We serve HFC's refineries under long-term pipeline and terminal, tankage and throughput agreements expiring from 2019 to 2026. Under these agreements, HFC agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. Additionally, such agreements require HFC to reimburse us for certain costs. These minimum annual payments or revenues are subject to annual tariff rate adjustments on July 1, based on the PPI or FERC index. As of December 31, 2013, these agreements with HFC will result in minimum annualized payments to us of $225.5 million.

If HFC fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. Under certain of the agreements, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.

We have a pipelines and terminals agreement with Alon expiring in 2020 under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue that also is

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subject to annual tariff rate adjustments. Also we have a capacity lease agreement under which we lease Alon space on our Orla to El Paso pipeline for the shipment of refined product. The terms under this lease agreement expire beginning in 2018 through 2022. As of December 31, 2013, these agreements with Alon will result in minimum annualized payments to us of $31.8 million.

A significant reduction in revenues under these agreements could have a material adverse effect on our results of operations.

Under certain provisions of the Omnibus Agreement that we have with HFC, we pay HFC an annual administrative fee, currently $2.3 million, for the provision by HFC or its affiliates of various general and administrative services to us on behalf of HLS. This fee does not include the salaries of personnel employed by HFC who perform services for us or the cost of their employee benefits, which are separately charged to us by HFC. We also reimburse HFC and its affiliates for direct expenses they incur on our behalf.

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RESULTS OF OPERATIONS

Income, Distributable Cash Flow and Volumes The following tables present income, distributable cash flow and volume information for the years ended December 31, 2013, 2012 and 2011.

Year Ended December 31, Change from 2013 2012 2012 (In thousands, except per unit data) Revenues Pipelines: Affiliates-refined product pipelines $ 66,441$ 67,682$ (1,241 ) Affiliates-intermediate pipelines 25,397 28,540 (3,143 ) Affiliates-crude pipelines 48,749 45,888 2,861 140,587 142,110 (1,523 ) Third parties-refined product pipelines 41,837 37,521 4,316 182,424 179,631 2,793 Terminals, tanks and loading racks: Affiliates 111,781 103,472 8,309 Third parties 10,977 9,457 1,520 122,758 112,929 9,829 Total revenues 305,182 292,560 12,622 Operating costs and expenses Operations (exclusive of depreciation and amortization) 99,444 89,242 10,202 Depreciation and amortization 65,423 57,461 7,962 General and administrative 11,749 7,594 4,155 176,616 154,297 22,319 Operating income 128,566 138,263 (9,697 ) Equity in earnings of SLC Pipeline 2,826 3,364 (538 ) Interest expense, including amortization (47,010 ) (47,182 ) 172 Interest income 161 - 161 Loss on early extinguishment of debt - (2,979 ) 2,979 Gain on sale of assets 1,810 - 1,810 Other 61 10 51 (42,152 ) (46,787 ) 4,635 Income before income taxes 86,414 91,476 (5,062 ) State income tax (333 ) (371 ) 38 Net income 86,081 91,105 (5,024 ) Allocation of net loss attributable to Predecessors - 4,200 (4,200 ) Allocation of net loss (income) attributable to noncontrolling interests (6,632 ) (1,153 ) (5,479 ) Net income attributable to Holly Energy Partners 79,449 94,152 (14,703 ) General partner interest in net income, including incentive distributions (1) (27,523 ) (22,450 ) (5,073 )



Limited partners' interest in net income $ 51,926$ 71,702$ (19,776 ) Limited partners' earnings per unit-basic and diluted (1)

$ 0.88$ 1.29$ (0.41 ) Weighted average limited partners' units outstanding 58,246 55,696 2,550 EBITDA (2) $ 192,054$ 194,242$ (2,188 ) Distributable cash flow (3) $ 146,579$ 153,125$ (6,546 ) Volumes (bpd) Pipelines: Affiliates-refined product pipelines 107,493 107,509 (16 ) Affiliates-intermediate pipelines 128,475 127,169 1,306 Affiliates-crude pipelines 161,391 171,040 (9,649 ) 397,359 405,718 (8,359 ) Third parties-refined product pipelines 63,337 63,152 185 460,696 468,870 (8,174 ) Terminals and loading racks: Affiliates 255,108 271,549 (16,441 ) Third parties 63,791 53,456 10,335 318,899 325,005 (6,106 )



Total for pipelines and terminal assets (bpd) 779,595 793,875 (14,280 )

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Table of Contents ril 19, Years Ended December 31, Change from 2012 2011 2011 (In thousands, except per unit data) Revenues Pipelines: Affiliates-refined product pipelines $ 67,682$ 46,649$ 21,033 Affiliates-intermediate pipelines 28,540 21,948 6,592 Affiliates-crude pipelines 45,888 47,542 (1,654 ) 142,110 116,139 25,971 Third parties-refined product pipelines 37,521 38,216 (695 ) 179,631 154,355 25,276 Terminals, tanks and loading racks: Affiliates 103,472 52,122 51,350 Third parties 9,457 7,791 1,666 112,929 59,913 53,016 Total revenues 292,560 214,268 78,292 Operating costs and expenses Operations (exclusive of depreciation and amortization) 89,242 64,521 24,721 Depreciation and amortization 57,461 36,958 20,503 General and administrative 7,594 6,576 1,018 154,297 108,055 46,242 Operating income 138,263 106,213 32,050 Equity in earnings of SLC Pipeline 3,364 2,552 812 Interest expense, including amortization (47,182 ) (35,959 ) (11,223 ) Other expense 10 17 (7 ) (46,787 ) (33,390 ) (13,397 ) Income before income taxes 91,476 72,823 18,653 State income tax (371 ) (234 ) (137 ) Net income 91,105 72,589 18,516 Allocation of net loss attributable to Predecessors 4,200 6,351 (2,151 ) Allocation of net loss attributable to noncontrolling interests (1,153 ) 859 (2,012 ) Net income attributable to Holly Energy Partners 94,152 79,799 14,353 General partner interest in net income, including incentive distributions (1) (22,450 ) (16,806 ) (5,644 )



Limited partners' interest in net income $ 71,702$ 62,993$ 8,709 Limited partners' earnings per unit-basic and diluted (1)

$ 1.29$ 1.38$ (0.09 ) Weighted average limited partners' units outstanding 55,696 45,672 10,024 EBITDA (2) $ 194,242$ 149,766$ 44,476 Distributable cash flow (3) $ 153,125$ 100,295$ 52,830 Volumes (bpd) Pipelines: Affiliates-refined product pipelines 107,509 90,782 16,727 Affiliates-intermediate pipelines 127,169 93,419 33,750 Affiliates-crude pipelines 171,040 161,789 9,251 405,718 345,990 59,728 Third parties-refined product pipelines 63,152 52,361 10,791 468,870 398,351 70,519 Terminals and loading racks: Affiliates 271,549 193,645 77,904 Third parties 53,456 44,454 9,002 325,005 238,099 86,906



Total for pipelines and terminal assets (bpd) 793,875 636,450 157,425

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(1) Net income attributable to HEP is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner includes incentive distributions that are declared subsequent to quarter end. After the amount of incentive distributions is allocated to the general partner, the remaining net income attributable to HEP is allocated to the partners based on their weighted average ownership percentage during the period. (2) EBITDA is calculated as net income attributable to Holly Energy Partners plus (i) interest expense, net of interest income, (ii) state income tax and (iii) depreciation and amortization, excluding amounts related to Predecessor. EBITDA is not a calculation based upon GAAP. However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements, with the exception of EBITDA from discontinued operations. EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for compliance with financial covenants. See our calculation of EBITDA under Item 6, "Selected Financial Data." (3) Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts presented in our consolidated financial statements, with the general exceptions of a billed crude revenue settlement, maintenance capital expenditures and distributable cash flow from discontinued operations. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. Also it is used by management for internal analysis and for our performance units. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating. See our calculation of distributable cash flow under Item 6, "Selected Financial Data."



Results of Operations - Year Ended December 31, 2013 Compared with Year Ended December 31, 2012

Summary

Net income attributable to HEP for the year ended December 31, 2013 was $79.4 million, a $14.7 million decrease compared to the year ended December 31, 2012. This decrease in earnings is due principally to increased operating costs and expenses, including higher depreciation resulting from asset abandonment charges related to tankage permanently removed from service, combined with higher allocations of income to noncontrolling interests. Overall revenues increased but did not keep pace with the cost increases as pipeline volumes supporting HFC's Navajo refinery were reduced in 2013 as the refinery experienced a planned turnaround in the first quarter and unplanned refinery downtime in the fourth quarter. Limited partners' per unit interest in earnings decreased from $1.29 per unit in 2012 to $0.88 per unit in 2013 due to the income decreases combined with higher incentive distributions to the general partner.

Revenues for the year ended December 31, 2013 include the recognition of $7.8 million of prior shortfalls billed to shippers in 2012. As of December 31, 2013, deferred revenue on our consolidated balance sheet related to shortfalls billed was $12.0 million. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels, if and to the extent the pipeline system will not have necessary capacity to provide for shipments in excess of guaranteed levels, or when shipping rights expire unused.

Revenues

Total revenues for the year ended December 31, 2013 were $305.2 million, a $12.6 million increase compared to the year ended December 31, 2012. The revenue increase was due to the effect of annual tariff increases, higher cost reimbursement receipts from HFC and a $1.5 million increase in previously deferred revenue realized. Overall pipeline volumes were down 2% compared to the year ended December 31, 2012.

Revenues from our refined product pipelines were $108.3 million, an increase of $3.1 million compared to the year ended December 31, 2012, primarily due to the effects of a $3.3 million increase in previously deferred revenue realized and annual tariff increases. Shipments averaged 170.8 thousand barrels per day ("mbpd") compared to 170.7 mbpd for 2012.

Revenues from our intermediate pipelines were $25.4 million, a decrease of $3.1 million on shipments averaging 128.5 mbpd compared to 127.2 mbpd for the year ended December 31, 2012. The decrease in revenue is due to the effects of a $1.8 million decrease in deferred revenue realized and reduced volumes on certain high tariff pipeline segments.

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Revenues from our crude pipelines were $48.7 million, an increase of $2.9 million on shipments averaging of 161.4 mbpd compared to 171.0 mbpd for the year ended December 31, 2012. Although crude oil pipeline shipments were down, revenues increased due to the annual tariff increases and minimum billings on certain pipeline segments.

Revenues from terminal, tankage and loading rack fees were $122.8 million, an increase of $9.8 million compared to year ended December 31, 2012. The increase in revenues is due to annual fee increases and higher tank cost reimbursement receipts from HFC. Refined products terminalled in our facilities increased an average of 318.9 mbpd compared to 325.0 mbpd for 2012.

Operations Expense Operations expense for the year ended December 31, 2013 increased by $10.2 million compared to the year ended December 31, 2012. This increase is due to higher maintenance costs, environmental accruals, employee costs and property taxes, offset by a $3.5 million net tax refund related to payroll costs covering a multi-year period.

Depreciation and Amortization Depreciation and amortization for the year ended December 31, 2013 increased by $8.0 million compared to the year ended December 31, 2012 due principally to asset abandonment charges related to tankage permanently removed from service.

General and Administrative General and administrative costs for the year ended December 31, 2013 increased by $4.2 million compared to the year ended December 31, 2012 due to increased employee costs.

Equity in Earnings of SLC Pipeline Our equity in earnings of the SLC Pipeline was $2.8 million and $3.4 million for the years ended December 31, 2013 and 2012.

Interest Expense Interest expense for the year ended December 31, 2013 totaled $47.0 million, a decrease of $0.2 million compared to the year ended December 31, 2012. Our aggregate effective interest rate was 5.7% and 6.5% for the years ended December 31, 2013 and 2012, respectively.

Loss on Early Extinguishment of Debt We recognized a charge of $3.0 million upon the early extinguishment of our 6.25% senior notes for the year ended December 31, 2012. This charge related to the premium paid to noteholders upon their tender of an aggregate principal amount of $185.0 million and related financing costs that were previously deferred.

Gain on Sale of Assets The gain on the sale of assets for the year ended December 31, 2013 of $1.8 million is comprised of a gain of $2.0 million on the sale of property in El Paso, Texas, partially offset by a $0.2 million loss from the sale of our 50% ownership interest in product terminals located in Boise and Burley, Idaho.

State Income Tax We recorded state income tax expense of $333,000 and $371,000 for the years ended December 31, 2013 and 2012 which is solely attributable to the Texas margin tax. We are subject to the Texas margin tax that is based on our Texas sourced taxable margin. Due to a statutory change that was enacted in June 2013, we are now able to deduct additional expenses which will result in lower cash taxes to HEP in the current and future years.

Results of Operations-Year Ended December 31, 2012 Compared with Year Ended December 31, 2011

Summary

Net income attributable to HEP for the year ended December 31, 2012 was $94.2 million, a $14.4 million increase compared to the year ended December 31, 2011. This increase in earnings was due principally to increased pipeline shipments, earnings attributable to our November 2011 acquisition and annual tariff increases. These factors were offset partially by increased operating costs and expenses, higher interest expense and a loss on the early extinguishment of debt. Although net income attributable to HEP increased, limited partners' per unit interest in earnings decreased from $1.38 per unit in 2011 to $1.29 per unit in 2012. The principal factors that caused the decrease in limited partners' per unit interest, relative to the overall net income attributable to HEP increase, were higher incentive distributions to the general partner and the UNEV acquisition not yet being accretive to earnings, although it was accretive to distributable cash flow.

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Revenues for the year ended December 31, 2012 include the recognition of $4.0 million of prior shortfalls billed to shippers in 2011. Deficiency payments of $7.8 million associated with certain guaranteed shipping contracts were deferred during the year ended December 31, 2012.

Revenues

Total revenues for the year ended December 31, 2012 were $292.6 million, a $78.3 million increase compared to the year ended December 31, 2011. This was due principally to increased pipeline shipments, revenues attributable to our recent acquisitions and the effect of annual tariff increases partially offset by a $4.6 million decrease in previously deferred revenue realized under our guaranteed shipping contracts. Overall pipeline volumes were up 18% compared to the year ended December 31, 2011.

Revenues from our refined product pipelines were $105.2 million, an increase of $20.3 million compared to the year ended December 31, 2011. This included $15.0 million in revenues attributable to UNEV pipeline throughputs which commenced initial start-up activities in December 2011 partially offset by a $5.4 million decrease in previously deferred revenue realized under our guaranteed shipping contracts. Volumes shipped on our refined product pipelines averaged 170.7 thousand barrels per day compared to 143.1 mbpd for 2011.

Revenues from our intermediate pipelines were $28.5 million, an increase of $6.6 million compared to the year ended December 31, 2011. This included $3.4 million of increased revenues attributable to the Tulsa interconnect pipelines, which were placed in service in September 2011, and a $0.8 million increase in previously deferred revenue realized under our guaranteed shipping contracts. Volumes shipped on our intermediate pipelines averaged 127.2 mbpd compared to 93.4 mbpd for 2011.

Revenues from our crude pipelines were $45.9 million, a decrease of $1.7 million compared to the year ended December 31, 2011. Revenues for the year ended December 31, 2011 included $5.5 million attributable to a crude pipeline revenue settlement with HFC. Volumes shipped on our crude pipelines increased to an average of 171.0 mbpd compared to 161.8 mbpd for 2011.

Revenues from terminal, tankage and loading rack fees were $112.9 million, an increase of $53.0 million compared to year ended December 31, 2011. This increase was due principally to $45.4 million of increased revenues attributable to our terminal, tankage and loading racks serving HFC's El Dorado and Cheyenne refineries. Refined products terminalled in our facilities increased to an average of 325.0 mbpd compared to 238.1 mbpd for 2011.

Operations Expense Operations expense for the year ended December 31, 2012 increased by $24.7 million compared to the year ended December 31, 2011. This increase was due principally to increased operating costs of $9.6 million and $5.2 million attributable to the 2012 acquired UNEV pipeline and assets serving HFC's El Dorado and Cheyenne refineries, respectively, higher throughput levels as well as year-over-year increases in property taxes, maintenance service and payroll costs.

Depreciation and Amortization Depreciation and amortization for the year ended December 31, 2012 increased by $20.5 million compared to the year ended December 31, 2011. This increase was due principally to depreciation attributable to our recent acquisitions from HFC and capital projects. Also contributing were increases in asset abandonment charges related to tankage no longer in service.

General and Administrative General and administrative costs for the year ended December 31, 2012 increased by $1.0 million compared to the year ended December 31, 2011 due to timing of professional fees related to recent acquisitions.

Equity in Earnings of SLC Pipeline Our equity in earnings of the SLC Pipeline was $3.4 million and $2.6 million for the years ended December 31, 2012 and 2011.

Interest Expense Interest expense for the year ended December 31, 2012 totaled $47.2 million, an increase of $11.2 million compared to the year ended December 31, 2011. This increase reflected interest on a year-over-year increase in debt levels. Our aggregate effective interest rate was 6.5% and 6.7% for the years ended December 31, 2012 and 2011, respectively.

Loss on Early Extinguishment of Debt We recognized a charge of $3.0 million upon the early extinguishment of our 6.25% senior notes for the year ended December 31, 2012. This charge related to the premium paid to noteholders upon their tender of an aggregate principal amount of $185.0 million and related financing costs that were previously deferred.

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State Income Tax We recorded state income tax expense of $371,000 and $234,000 for the years ended December 31, 2012 and 2011 which was solely attributable to the Texas margin tax.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In November 2013, we amended the Credit Agreement increasing the size of the credit facility from $550 million to $650 million. Our $650 million senior secured revolving credit facility expires in November 2018 and is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit.

During the year ended December 31, 2013, we received advances totaling $310.6 million and repaid $368.6 million, resulting in net reduction of $58.0 million under the Credit Agreement and an outstanding balance of $363.0 million at December 31, 2013. If any particular lender under the Credit Agreement could not honor its commitment, we believe the unused capacity that would be available from the remaining lenders would be sufficient to meet our borrowing needs. Additionally, we review publicly available information on the lenders in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the Credit Agreement. We do not expect to experience any difficulty in the lenders' ability to honor their respective commitments, and if it were to become necessary, we believe there would be alternative lenders or options available.

Under our registration statement filed with the SEC using a "shelf" registration process, we currently have the ability to raise up to $2.0 billion by offering securities, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.

We believe our current cash balances, future internally generated funds and funds available under the Credit Agreement will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future.

In February, May, August and November 2013, we paid regular quarterly cash distributions of $0.4700, $0.4775, $0.4850 and $0.4925, respectively, on all units in an aggregate amount of $139.5 million. Included in this aggregate amount were $24.6 million of incentive distribution payments to the general partner.

Contemporaneously with our UNEV Pipeline interest acquisition on July 12, 2012, HFC (our general partner) agreed to forego its right to incentive distributions of $1.25 million per quarter over twelve consecutive quarterly periods following the close of the transaction and up to an additional four quarters in certain circumstances.

Cash and cash equivalents increased by $1.1 million during the year ended December 31, 2013. The cash flows provided by operating activities of $183.1 million were greater than the cash flows used for financing and investing activities of $132.9 million and $49.1 million, respectively. Working capital decreased by $18.4 million to a deficit of $6.6 million at December 31, 2013 from $11.8 million at December 31, 2012.

Cash Flows-Operating Activities Year Ended December 31, 2013 Compared with Year Ended December 31, 2012 Cash flows from operating activities increased by $21.9 million from $161.1 million for the year ended December 31, 2012 to $183.1 million for the year ended December 31, 2013. This increase is due principally to $30.7 million of greater cash receipts for services performed in the year ended December 31, 2013 as compared to the prior year, partially offset by payments made for increased operating expenses.

Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Under certain agreements with these shippers, they have the right to recapture these amounts if future volumes exceed minimum levels. We billed $7.8 million during the year ended December 31, 2012 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the year ended December 31, 2013. Another $12.0 million is included as deferred revenue on our balance sheet at December 31, 2013 related to shortfalls billed during the year ended December 31, 2013.

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Year Ended December 31, 2012 Compared with Year Ended December 31, 2011 Cash flows from operating activities increased by $62.4 million from $99.0 million for the year ended December 31, 2011 to $161.4 million for the year ended December 31, 2012. This increase is due principally to $63.0 million in additional cash collections from our customers, partially offset by payments attributable to increased operating expenses.

We billed $4.6 million during the year ended December 31, 2011 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the year ended December 31, 2012. Another $7.8 million was included in our accounts receivable at December 31, 2012 related to shortfalls that occurred during the year ended December 31, 2012.

Cash Flows-Investing Activities Year Ended December 31, 2013 Compared with Year Ended December 31, 2012 Cash flows used for investing activities increased by $6.5 million from $42.6 million for the year ended December 31, 2012 to $49.1 million for the year ended December 31, 2013. During the years ended December 31, 2013 and 2012, we invested $52.1 million and $42.6 million in additions to properties and equipment, respectively. During the year ended December 31, 2013, we received $2.7 million proceeds from the sale of assets. Distributions in excess of equity in earnings of the SLC Pipeline was $0.3 million for the years ended December 31, 2013 and 2012.

Year Ended December 31, 2012 Compared with Year Ended December 31, 2011 Cash flows used for investing activities decreased by $163.4 million from $206.3 million for the year ended December 31, 2011 to $42.9 million for the year ended December 31, 2012. During the years ended December 31, 2012 and 2011, we invested $42.9 million and $206.3 million in additions to properties and equipment, respectively. The decrease is attributable to lower expenditures in 2012 as a result of the completion of the UNEV pipeline in 2011. Distributions in excess of equity in earnings of the SLC Pipeline was $0.3 million and $0.1 million for the years ended December 31, 2012 and 2011.

Cash Flows-Financing Activities Year Ended December 31, 2013 Compared with Year Ended December 31, 2012 Cash flows used for financing activities were $132.9 million for the year ended December 31, 2013 compared to $119.7 million for the year ended December 31, 2012, an increase of $13.2 million. During the year ended December 31, 2013, we received $310.6 million and repaid $368.6 million in advances under the Credit Agreement, received net proceeds of $73.4 million from the common unit public offering and $1.5 million from the general partner to maintain its 2% interest. Additionally, we paid $139.5 million in regular quarterly cash distributions to our general and limited partners, and paid $5.6 million for the purchase of common units for recipients of our incentive grants. Also, we distributed $3.1 million to the UNEV noncontrolling interest joint venture partner and paid $1.3 million in financing costs to amend our Credit Facility. During the year ended December 31, 2012, we received $587.0 million and repaid $366.0 million in advances under the Credit Agreement, received net proceeds of $294.8 million from the issuance of our 6.5% senior notes and repaid $260.2 million of our notes. We paid HFC $260.9 million as partial consideration for the acquisition of HFC's 75% interest in UNEV. Additionally, we paid $122.8 million in regular quarterly cash distributions to our general and limited partners, we received $15.0 million from UNEV's joint venture partners, received $1.8 million from our general partner, paid $3.2 million in financing costs to amend our Credit Agreement and paid $4.9 million for the purchase of common units for recipients of our incentive grants.

Year Ended December 31, 2012 Compared with Year Ended December 31, 2011 Cash flows used for financing activities were $119.7 million for the year ended December 31, 2012, as discussed above, compared to cash provided of $105.6 million for the year ended December 31, 2011, a decrease of $225.3 million. During the year ended December 31, 2011, we received $118.0 million and repaid $77.0 million in advances under the Credit Agreement, received proceeds of $75.8 million from the issuance of our common units, and repaid $77.1 million of our promissory notes. Additionally, we paid $91.5 million in regular quarterly cash distributions to our general and limited partners, we received $156.5 million from UNEV's joint venture partners, received $5.9 million from our general partner, incurred $3.2 million in financing costs upon the issuance of the 8.25% senior notes, and paid $1.6 million for the purchase of common units for recipients of our incentive grants.

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Capital Requirements Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements have consisted of, and are expected to continue to consist of, maintenance capital expenditures and expansion capital expenditures. "Maintenance capital expenditures" represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations. "Expansion capital expenditures" represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition. Expansion capital expenditures include expenditures to acquire assets, to grow our business and to expand existing facilities, such as projects that increase throughput capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

Each year the HLS board of directors approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, additional projects may be approved. The funds allocated for a particular capital project may be expended over a period in excess of a year, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year's capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2014 capital budget is comprised of $7.3 million for maintenance capital expenditures and $26.2 million for expansion capital expenditures. We expect to spend approximately $52 million in cash for capital projects approved in 2014 plus those approved in prior years but not yet completed, including the expansion of our crude oil transportation system in southeastern New Mexico and the UNEV project discussed below. In addition to our capital budget, we may spend funds periodically to perform capital upgrades to our assets where a customer reimburses us for such costs. These reimbursements would be required under contractual agreements, and the upgrades would generally benefit the customer over the remaining life of such agreements.

We are proceeding with the expansion of our crude oil transportation system in southeastern New Mexico in response to increased crude oil production in the area. The expansion should provide shippers with additional pipeline takeaway capacity to either common carrier pipeline stations for transportation to major crude oil markets or to HFC's New Mexico refining facilities. To complete the project, we are converting an existing refined products pipeline to crude oil service, constructing several new pipeline segments, expanding an existing pipeline, and building new truck unloading stations and crude storage capacity. Excluding the value of the existing pipeline to be converted, total capital expenditures are expected to be between $45 million and $50 million. We expect that the increase over the original budget range of $35 million to $40 million will be recovered from HFC over a five year period through an additional fee on shipped volumes. We estimate the project will provide increased capacity of up to 100,000 barrels per day across the system and anticipate it will be in full service no later than August 2014.

UNEV is proceeding with a project to enhance its product terminal in Las Vegas, Nevada. We expect that the project will cost approximately $13 million with construction expected to be completed no later than the second quarter of 2014.

HFC and we are collaborating to evaluate the construction of a rail facility that would enable crude oil loading and unloading near HFC's Artesia and/or Lovington, New Mexico refining facilities. The rail project, which would be connected to our crude oil pipeline transportation system in southeastern New Mexico, would have an initial capacity of up to 70,000 barrels per day and would enable access to a variety of crude oil types including West Texas Intermediate (WTI), West Texas Sour (WTS) and Western Canadian Select (WCS). The project would provide both additional crude oil takeaway options for producers as crude production in the region continues to grow, and an expanded set of crude oil sourcing options for HFC. We anticipate project completion would take nine to twelve months once the decision to proceed is made. Our decision to proceed with this project is dependent upon shipper interest, which at present does not support project completion.

We expect that our currently planned sustaining and maintenance capital expenditures, as well as expenditures for acquisitions and capital development projects will be funded with existing cash generated by operations, the sale of additional limited partner common units, the issuance of debt securities and advances under our Credit Agreement, or a combination thereof. With volatility and uncertainty at times in the credit and equity markets, there may be limits on our ability to issue new debt or equity financing. Additionally, due to pricing movements in the debt and equity markets, we may not be able to issue new debt and equity securities at acceptable pricing. Without additional capital beyond amounts available under the Credit Agreement, our ability to obtain funds for some of these capital projects may be limited.

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On July 12, 2012, we acquired HFC's 75% interest in UNEV. We paid consideration consisting of $260.0 million in cash and 2,059,800 of our common units. We paid an additional $0.9 million to HFC for a post-closing working capital adjustment. Also under the terms of the transaction, we issued to HFC a Class B unit comprising a noncontrolling equity interest in a wholly-owned subsidiary subject to redemption to the extent that HFC is entitled to a 50% interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2016 and ending in June 2032, subject to certain limitations.

Credit Agreement On November 22, 2013, we amended our credit agreement increasing the size of the credit facility from $550.0 million to $650.0 million. Our $650.0 million senior secured revolving credit facility expires in November 2018 (the "Credit Agreement") and is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit.

Our obligations under the Credit Agreement are collateralized by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to HEP Logistics Holdings, L.P. ("HEP Logistics"), our general partner, and guaranteed by our material wholly-owned subsidiaries. Any recourse to HEP Logistics would be limited to the extent of its assets, which other than its investment in us, are not significant. We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs.

Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.625% to 1.50%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 1.625% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on the unused portion of the Credit Agreement at an annual rate ranging from 0.30% to 0.45% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.

The Credit Agreement imposes certain requirements on us which we are in compliance with currently, including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter into a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio, total debt to EBITDA ratio and senior debt to EBITDA ratio. If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.

Senior Notes In March 2012, we issued $300 million in aggregate principal amount outstanding of 6.5% senior notes maturing March 1, 2020 (the "6.5% Senior Notes"). Net proceeds of $294.8 million were used in March and April 2012 to redeem $185.0 million aggregate principal amount of 6.25% senior notes maturing March 1, 2015 (the "6.25 Senior Notes") tendered pursuant to a cash tender offer and consent solicitation, to repay $72.9 million in promissory notes due to HFC as discussed below, to pay related fees, expenses and accrued interest in connection with these transactions and to repay borrowings under the Credit Agreement.

We also have $150 million in aggregate principal amount outstanding of 8.25% senior notes maturing March 15, 2018 (the "8.25% Senior Notes"). On February 12, 2014, we announced that we will redeem all of our outstanding 8.25% Senior Notes. The redemption price will be equal to 104.125% of the principal amount for a total payment to the holders of the notes of approximately $156.2 million plus accrued interest. The redemption of the 8.25% Senior Notes is scheduled to occur on March 15, 2014. We plan to fund the redemption with borrowings under our Credit Agreement.

Our 6.5% Senior Notes and 8.25% Senior Notes (collectively, the "Senior Notes") are unsecured and impose certain restrictive covenants which we are in compliance with currently, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the Senior Notes are rated investment grade by both Moody's and Standard & Poor's and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights at varying premiums over face value under the Senior Notes.

Indebtedness under the Senior Notes is recourse to HEP Logistics, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics would be limited to the extent of its assets, which other than its investment in us, are not significant.

Our purchase and contribution agreements with HFC with respect to the intermediate pipelines acquired in 2005 and the crude pipelines and tankage assets acquired in 2008, restrict us from selling these pipelines and terminals acquired from HFC. Under

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these agreements, we are restricted from prepaying borrowings and long-term debt to outstanding balances below $206 million prior to 2015 and $171 million prior to 2018, subject to certain limited exceptions.

Promissory Notes In November 2011, we issued senior unsecured promissory notes to HFC (the "Promissory Notes") having an aggregate principal amount of $150.0 million to finance a portion of our November 9, 2011 acquisition of assets located at HFC's El Dorado and Cheyenne refineries. In December 2011, we repaid $77.1 million of outstanding principal using proceeds received in our December 2011 common unit offering and existing cash. We repaid the remaining $72.9 million balance in March 2012.

Long-term Debt The carrying amounts of our long-term debt are as follows: December 31, December 31, 2013 2012 (In thousands) Credit Agreement $ 363,000$ 421,000 6.5% Senior Notes Principal 300,000 300,000



Unamortized discount (4,073 ) (4,725 )

295,927 295,275 8.25% Senior Notes Principal 150,000 150,000



Unamortized discount (1,297 ) (1,601 )

148,703 148,399



Total long-term debt $ 807,630$ 864,674

See "Risk Management" for a discussion of our interest rate swaps.

Long-term Contractual Obligations The following table presents our long-term contractual obligations as of December 31, 2013. Payments Due by Period Less than Over 5 Total 1 Year 1-3 Years 3-5 Years Years (In thousands)



Long-term debt - principal $ 813,000 $ - $ - $ 513,000$ 300,000 Long-term debt - interest 221,804 39,748 79,497 73,309 29,250 Pipeline operating lease 23,423 6,692 13,385 3,346

- Right-of-way leases 1,184 182 344 296 362 Other 17,034 1,987 3,904 3,904 7,239 Total $ 1,076,445$ 48,609$ 97,130$ 593,855$ 336,851



Long-term debt consists of outstanding principal under the Credit Agreement and Senior Notes. Interest on the credit agreement is calculated using the rate in effect at December 31, 2013. The above table does not reflect the pending redemption of the 8.25% Senior Notes scheduled for March 2014. The pipeline operating lease amounts above reflect the exercise of the first of three 10-year extensions, expiring in 2017, on our lease agreement for the refined products pipeline between White Lakes Junction and Kuntz Station in New Mexico. Most of our right-of-way agreements are renewable on an annual basis, and the right-of-way lease payments above include only obligations under the remaining non-cancelable terms of these agreements at December 31, 2013. For the foreseeable future, we intend to continue renewing these agreements and expect to incur right-of-way expenses in addition to the payments listed. Other contractual obligations consist of site service agreements with HFC expiring in 2024 through 2026, for the provision of certain maintenance and utility costs that relate to our assets located at HFC's refinery facilities.

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Impact of Inflation Inflation in the United States has been relatively moderate in recent years and did not have a material impact on our results of operations for the years ended December 31, 2013, 2012 and 2011. Historically, the PPI has increased an average of 2.2% annually over the past 5 calendar years.

The substantial majority of our revenues are generated under long-term contracts that provide for increases in our rates and minimum revenue guarantees annually for increases in the PPI. Certain of these contracts have provisions that limit the level of annual PPI percentage rate increases. Although the recent PPI increase may not be indicative of additional increases to be realized in the future, a significant and prolonged period of high inflation could adversely affect our cash flows and results of operations if costs increase at a rate greater than the fees we charge our shippers.

Environmental Matters Our operation of pipelines, terminals, and associated facilities in connection with the transportation and storage of refined products and crude oil is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position given that the operations of our competitors are similarly affected. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A major discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage. Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC and occurring or existing prior to the date of such transfers. We have an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon in 2005, under which Alon will indemnify us subject to certain monetary and time limitations.

There are environmental remediation projects that are currently in progress that relate to certain assets acquired from HFC. Certain of these projects were underway prior to our purchase and represent liabilities of HFC as the obligation for future remediation activities was retained by HFC. At December 31, 2013, we have an accrual of $3.6 million that relates to environmental clean-up projects for which we have assumed liability or for which the indemnity provided for by HFC has expired or will expire. The remaining projects, including assessment and monitoring activities, are covered under the HFC environmental indemnification discussed above and represent liabilities of HFC.

CRITICAL ACCOUNTING POLICIES



Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.

Revenue Recognition Revenues are recognized as products are shipped through our pipelines and terminals. Additional pipeline transportation revenues result from an operating lease by Alon USA, L.P. of an interest in the capacity of one of our pipelines.

Billings to customers for their obligations under their quarterly minimum revenue commitments are recorded as deferred revenue liabilities if the customer has the right to receive future services for these billings. The revenue is recognized at the earlier of:

the customer receiving the future services provided by these billings,

the period in which the customer is contractually allowed to receive the services expires, or our determination that we will not be required to provide services within the allowed period.



We determine that we will not be required to provide services within the allowed period when, based on current and projected shipping levels, our pipeline systems will not have the necessary capacity to enable a customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit within its respective contractual shortfall make-up period.

Goodwill and Long-Lived Assets Goodwill represents the excess of our cost of an acquired business over the fair value of the assets acquired, less liabilities assumed. Goodwill is not amortized and is tested for impairment annually or more frequently if events or changes in circumstances indicate goodwill may be impaired. We test goodwill at the reporting unit level for impairment annually and between annual tests if events or changes in circumstances indicate the carrying amount may exceed fair value. Recoverability is determined by comparing the estimated fair value of a reporting unit to the carrying value, including the related goodwill, of that reporting unit. We use the present value of the expected future net cash flows and market multiple analyses to determine the estimated fair values of the reporting units. The impairment test requires the use of projections, estimates and assumptions as to the future performance of our operations. Actual results could differ from projections resulting in revisions to our assumptions, and if required, recognizing an impairment loss.

We evaluate long-lived assets, including definite-lived intangible assets, for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset's carrying value exceeds its fair value.

There have been no impairments to goodwill or our long-lived assets as of December 31, 2013.

Contingencies

It is common in our industry to be subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We are required to assess the likelihood of any adverse judgments or outcomes to these types of matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these types of contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to developments in each matter or changes in approach such as a change in settlement strategy in dealing with these potential matters.

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We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.

As of December 31, 2013, we have three interest rate swaps, designated as a cash flow hedge, that hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on $305.0 million of Credit Agreement advances. Our first interest rate swap effectively converts $155.0 million of our LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.00% as of December 31, 2013, which equaled an effective interest rate of 2.99%. This swap contract matures in February 2016. In August 2012, we entered into two similar interest rate swaps with identical terms which effectively convert $150.0 million of our LIBOR based debt to fixed rate debt having an interest rate of 0.74% plus an applicable margin of 2.00% as of December 31, 2013, which equaled an effective interest rate of 2.74%. Both of these swap contracts mature in July 2017.

We review publicly available information on our counterparties in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the interest rate swap contracts. These counterparties are large financial institutions. Furthermore, we have not experienced, nor do we expect to experience, any difficulty in the counterparties honoring their respective commitments.

The market risk inherent in our debt positions is the potential change arising from increases or decreases in interest rates as discussed below.

At December 31, 2013, we had an outstanding principal balance on our 6.5% Senior Notes and 8.25% Senior Notes of $300 million and $150 million, respectively. A change in interest rates generally would affect the fair value of the Senior Notes, but not our earnings or cash flows. At December 31, 2013, the fair values of our 6.5% Senior Notes and 8.25% Senior Notes were $313.5 million and $158.3 million, respectively. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6.5% Senior Notes and 8.25% Senior Notes at December 31, 2013 would result in a change of approximately $9.1 million and $3.8 million, respectively, in the fair value of the underlying notes.

For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2013, borrowings outstanding under the Credit Agreement were $363.0 million. By means of our cash flow hedges, we have effectively converted the variable rate on $305.0 million of outstanding borrowings to a fixed rate. For the remaining unhedged Credit Agreement borrowings of $58.0 million, a hypothetical 10% change in interest rates applicable to the Credit Agreement would not materially affect our cash flows.

Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.

We have a risk management oversight committee that is made up of members from our senior management. This committee monitors our risk environment and provides direction for activities to mitigate, to an acceptable level, identified risks that may adversely affect the achievement of our goals.


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