Description
Holly Energy Partners, L.P. Corp HollyFrontier bought 4,837,515 shares on 7-12-2012 at $ 50.65
BUSINESS OVERVIEW
OVERVIEW
Holly Energy Partners, L.P. (“HEP”) is a Delaware limited partnership engaged principally in the business of operating a system of petroleum product and crude pipelines, storage tanks, distribution terminals and loading rack facilities in west Texas, New Mexico, Utah, Oklahoma, Wyoming, Kansas, Arizona, Idaho and Washington. We were formed in Delaware in 2004 and maintain our principal corporate offices at 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507. Our telephone number is 214-871-3555 and our internet website address is www.hollyenergy.com . The information contained on our website does not constitute part of this Annual Report on Form 10-K. A copy of this Annual Report on Form 10-K will be provided without charge upon written request to the Vice President, Investor Relations at the above address. A direct link to our filings at the U.S. Securities and Exchange Commission (“SEC”) website is available on our website on the Investors page. Also available on our website are copies of our Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, and Code of Business Conduct and Ethics, all of which will be provided without charge upon written request to the Vice President, Investor Relations at the above address. 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. “HFC” refers to HollyFrontier Corporation (formerly known as Holly Corporation) and its subsidiaries, other than HEP and its subsidiaries and other than Holly Logistic Services, L.L.C. (“HLS”), a subsidiary of HollyFrontier Corporation that is the general partner of the general partner of HEP and manages HEP. HFC changed its name in connection with the consummation of its merger of equals with Frontier Oil Corporation effective July 1, 2011.
We own and operate petroleum product and crude 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 USA, Inc.’s (“Alon”) refinery in Big Spring, Texas. HFC currently owns a 42% interest in us, including the 2% general partner interest. Additionally, we own a 25% joint venture interest in a 95-mile intrastate crude oil pipeline system (the “SLC Pipeline”) that serves refineries in the Salt Lake City 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.
2011 Acquisition
Legacy Frontier Tankage and Terminal 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 3,807,615 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 $47 million.
2010 Acquisitions
Tulsa East / Lovington Storage Asset Transaction
On March 31, 2010, we acquired from HFC certain storage assets for $88.6 million consisting of hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at HFC’s Tulsa refinery east facility. Also, as part of this same transaction, we acquired HFC’s asphalt loading rack facility located at its Navajo refinery facility in Lovington, New Mexico for $4.4 million.
2009 Acquisitions
Sinclair Logistics and Storage Assets Transaction
On December 1, 2009, we acquired from Sinclair Oil Company (“Sinclair”) storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at its refinery located in Tulsa, Oklahoma for $79.2 million. The purchase price consisted of $25.7 million in cash, including $4.2 million in taxes paid and 1,373,609 of our common units having a fair value of $53.5 million. Separately, HFC, also a party to the transaction, acquired Sinclair’s Tulsa refinery.
Roadrunner / Beeson Pipelines Transaction
Also on December 1, 2009, we acquired from HFC two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects the Navajo refinery Lovington facility to a terminus of Centurion Pipeline L.P.’s pipeline extending between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil pipeline that connects our New Mexico crude oil gathering system to the Navajo refinery Lovington facility (the “Beeson Pipeline”).
Tulsa West Loading Racks Transaction
On August 1, 2009, we acquired from HFC certain truck and rail loading/unloading facilities located at HFC’s Tulsa refinery west facility for $17.5 million. The racks load refined products and lube oils produced at the Tulsa refinery onto rail cars and/or tanker trucks.
Lovington-Artesia Pipeline Transaction
On June 1, 2009, we acquired from HFC a newly constructed, 16-inch intermediate pipeline for $34.2 million that runs 65 miles from the Navajo refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico.
SLC Pipeline Joint Venture Interest
On March 1, 2009, we acquired a 25% joint venture interest in the SLC Pipeline, a 95-mile intrastate pipeline system that we jointly own with Plains. The total cost of our investment in the SLC Pipeline was $28 million, consisting of the capitalized $25.5 million joint venture contribution and the $2.5 million finder’s fee paid to HFC that was expensed as acquisition costs.
HFC Capacity Expansion
Also in March 2009, HFC, our largest customer, completed a 15,000 barrels per stream day (“bpsd”) capacity expansion of its Navajo refinery increasing refining capacity to 100,000 bpsd, or by 18%.
Rio Grande Pipeline Sale
On December 1, 2009, we sold our 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35 million.
Agreements with HFC and Alon
We serve HFC’s refineries under long-term pipeline and terminal, tankage and throughput agreements expiring in 2019 through 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. These minimum annual payments or revenues are subject to annual tariff rate adjustments on July 1, based on the Producer Price Index (“PPI”) or the Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2011, these agreements with HFC will result in minimum annualized payments to us of $192 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 also 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 subject to annual tariff rate adjustments. Also, we have a capacity lease agreement with Alon under which we lease Alon space on our Orla to El Paso pipeline for the shipment of up to 15,000 barrels of refined product per day. The terms under this agreement expire beginning in 2018 through 2022. As of December 31, 2011, these agreements with Alon will result in minimum annualized payments to us of $30 million.
A significant reduction in revenues under these agreements would have a material adverse effect on our results of operations.
Furthermore, if new laws or regulations that affect terminals or pipelines are enacted that require us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we will have the right after we have made efforts to mitigate their effects to negotiate a monthly surcharge on HFC for the use of the terminals or to file for an increased tariff rate for use of the pipelines to cover HFC’s pro rata portion of the cost of complying with these laws or regulations including a reasonable rate of return. In such instances, we will negotiate in good faith with HFC to agree on the level of the monthly surcharge or increased tariff rate.
Omnibus Agreement
Under certain provisions of an omnibus agreement with HFC (the “Omnibus Agreement”), we pay HFC an annual administrative fee for the provision by HFC or its affiliates of various general and administrative services to us, currently $2.3 million. This fee includes expenses incurred by HFC and its affiliates to perform centralized corporate functions, such as executive management, legal, accounting, treasury, information technology and other corporate services, including the administration of employee benefit plans. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, such as 401(k), pension and health insurance benefits, which are separately charged to us by HFC. We also reimburse HFC and its affiliates for direct expenses they incur on our behalf. In addition, we also pay for our own direct general and administrative costs, including costs relating to operating as a separate publicly held entity, such as costs for preparation of partners’ K-1 tax information, SEC filings, investor relations, directors’ compensation, directors’ and officers’ insurance and registrar and transfer agent fees.
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, special 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 2012 capital budget is comprised of $8.9 million for maintenance capital expenditures and $25.8 million for expansion capital expenditures.
We recently have made certain modifications to our crude oil gathering and trunk line system that have effectively increased our ability to gather and transport an additional 10,000 barrels per day (“bpd”) of Delaware Basin crude oil in response to increased drilling activity in southeast New Mexico. Furthermore, we have developed a project to replace a 5-mile section of this pipeline system that will allow for an additional 15,000 bpd of capacity that will be executed as needed if Delaware Basin crude volumes continue to increase. This project is estimated to cost approximately $2 million. We have a second project which consists of the reactivation and conversion to crude oil service of a 70-mile, 8-inch petroleum products pipeline owned by us. Once in service, this pipeline will initially be capable of transporting up to 35,000 bpd of crude oil from southeast New Mexico to third-party common carrier pipelines in west Texas for further transport to major crude oil markets. The scope of this project is being finalized. Subject to receipt of acceptable shipper support and board approval, this project could be operational in early 2013.
We are in discussions with HFC regarding our option to purchase its 75% equity interest in UNEV Pipeline, LLC (the “UNEV Pipeline”), a joint venture pipeline that is capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada. The initial capacity of this pipeline is 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The total construction cost of this pipeline, including terminals and ethanol blending and storage facilities, was approximately $410 million. HFC’s share of the cost is $308 million. The pipeline was mechanically complete in November 2011, and initial start-up activities commenced in December 2011. We are not obligated to purchase the UNEV Pipeline nor are we subject to any fees or penalties if HLS’ board of directors decides not to proceed with this opportunity.
We expect that our currently planned sustaining and maintenance capital expenditures, as well as expenditures for acquisitions and capital development projects such as our option to purchase HFC’s interest in the UNEV Pipeline described above, 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 $375 million senior secured credit agreement expiring in February 2016 (the “Amended 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 Amended Credit Agreement, our ability to fund some of these capital projects may be limited, especially the UNEV Pipeline.
SAFETY AND MAINTENANCE
We perform preventive and normal maintenance on all of our pipeline systems and make repairs and replacements when necessary or appropriate. We also conduct routine and required inspections of our pipelines and other assets as required by code or regulation. We inject corrosion inhibitors into our mainlines to help control internal corrosion. External coatings and impressed current cathodic protection systems are used to protect against external corrosion. We conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards. We regularly monitor, test and record the effectiveness of these corrosion-inhibiting systems.
We monitor the structural integrity of selected segments of our pipeline systems through a program of periodic internal inspections using both “dent pigs” and electronic “smart pigs”, as well as hydrostatic testing that conforms to federal standards. We follow these inspections with a review of the data and we make repairs as necessary to ensure the integrity of the pipeline. We have initiated a risk-based approach to prioritizing the pipeline segments for future smart pig runs or other approved integrity testing methods. We believe this approach will ensure that the pipelines that have the greatest risk potential receive the highest priority in being scheduled for inspections or pressure tests for integrity. Our inspection process complies with all Department of Transportation (“DOT”) and Code of Federal Regulations (“CFR”) 49 CFR Part 195 requirements.
Maintenance facilities containing equipment for pipe repairs, spare parts, and trained response personnel are located along the pipelines. Employees participate in simulated spill deployment exercises on a regular basis. They also participate in actual spill response boom deployment exercises in planned spill scenarios in accordance with Oil Pollution Act of 1990 requirements. We believe that all of our pipelines have been constructed and are maintained in all material respects in accordance with applicable federal, state, and local laws; the regulations and standards prescribed by the American Petroleum Institute, the DOT; and accepted industry practice.
At our terminals, tanks designed for gasoline storage are equipped with internal or external floating roofs that minimize emissions and prevent potentially flammable vapor accumulation between fluid levels and the roof of the tank. Our terminal facilities have facility response plans, spill prevention and control plans, and other plans and programs to respond to emergencies.
Many of our terminal loading racks are protected with water deluge systems activated by either heat sensors or an emergency switch. Several of our terminals are also protected by foam systems that are activated in case of fire. All of our terminals are subject to participation in a comprehensive environmental management program to assure compliance with applicable air, solid waste, and wastewater regulations.
COMPETITION
As a result of our physical integration with HFC’s refineries, our contractual relationship with HFC under the Omnibus Agreement and the HFC pipelines and terminals, tankage and throughput agreements, we believe that we will not face significant competition for barrels of refined products transported from HFC’s refineries, particularly during the terms of our long-term transportation agreements with HFC expiring in 2019 through 2026. Additionally, under our throughput agreement with Alon expiring in 2020, we believe that we will not face significant competition for those barrels of refined products we transport from Alon’s Big Spring refinery.
However, we do face competition from other pipelines that may be able to supply the end-user markets of HFC or Alon with refined products on a more competitive basis. Additionally, If HFC’s wholesale customers reduced their purchases of refined products due to the increased availability of cheaper product from other suppliers or for other reasons, the volumes transported through our pipelines could be reduced, which, subject to the minimum revenue commitments, could cause a decrease in cash and revenues generated from our operations.
The petroleum refining business is highly competitive. Among HFC’s competitors are some of the world’s largest integrated petroleum companies, which have their own crude oil supplies and distribution and marketing systems. HFC competes with independent refiners as well. Competition in particular geographic areas is affected primarily by the amounts of refined products produced by refineries located in such areas and by the availability of refined products and the cost of transportation to such areas from refineries located outside those areas.
In addition, we face competition from trucks that deliver product in a number of areas we serve. Although their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volumes in many areas we serve. The availability of truck transportation places some competitive constraints on us.
Historically, the significant majority of the throughput at our terminal facilities has come from HFC, with the exception of third-party receipts at the Spokane terminal, Alon volumes at El Paso, and the Abilene and Wichita Falls terminals that serve Alon’s Big Springs refinery.
Our ten refined product terminals compete with other independent terminal operators as well as integrated oil companies based on terminal location, price, versatility and services provided. Our competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading arms.
RATE REGULATION
Some of our existing pipelines are subject to rate regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for oil pipelines, a category that includes crude oil and petroleum product pipelines, be just and reasonable and non-discriminatory. The Interstate Commerce Act permits challenges to rates that are already on file and in effect by complaint. A successful challenge under a complaint may result in the complainant obtaining damages or reparations for up to two years prior to the date the complaint was filed. The Interstate Commerce Act also permits challenges to a proposed new or changed rate by a protest. A successful challenge under a protest may result in the protestant obtaining refunds or reparations from the date the proposed new or changed rate becomes effective. In either challenge process, the third party must be able to show it has a substantial economic interest in those rates to proceed. The FERC generally has not investigated interstate rates on its own initiative but will likely become a party to any proceedings when the rates receive either a complaint or a protest. However, the FERC is not prohibited from bringing an interstate rate under investigation without a third-party intervention.
MANAGEMENT DISCUSSION FROM LATEST 10K
OVERVIEW
Holly Energy Partners, L.P. is a Delaware limited partnership. We own and operate petroleum product and crude 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 Big Spring refinery in Big Spring, Texas. HFC currently owns a 42% interest in us, including the 2% general partner interest. Additionally, we own 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 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.
Legacy Frontier Tankage and Terminal 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 3,807,615 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 $47 million.
Agreements with HFC and Alon
We serve HFC’s refineries under long-term pipeline and terminal, tankage and throughput agreements expiring in 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. 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, 2011, these agreements with HFC will result in minimum annualized payments to us of $192 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 also 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 subject to annual tariff rate adjustments. Also, we have a capacity lease agreement with Alon under which we lease Alon space on our Orla to El Paso pipeline for the shipment of up to 15,000 barrels of refined product per day. The terms under this agreement expire beginning in 2018 through 2022. As of December 31, 2011, these agreements with Alon will result in minimum annualized payments to us of $30 million.
A significant reduction in revenues under these agreements would 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. This fee does not include the salaries of pipeline and terminal personnel 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.
Results of Operations – Year Ended December 31, 2011 Compared with Year Ended December 31, 2010
Summary
Net income for the year ended December 31, 2011 was $78 million, a $19.1 million increase compared to the year ended December 31, 2010. This increase in overall earnings is due principally to increased pipeline shipments, earnings attributable to our November 2011 asset acquisitions and an increase in previously deferred revenue realized. Also contributing to earnings was a settlement with HFC relating to a clarification of the appropriate charges for certain past deliveries into our crude pipeline system. These factors were partially offset by an overall increase in operating costs and expenses.
Revenues for the year ended December 31, 2011 included the recognition of $12.4 million of prior shortfalls billed to shippers in 2011. Deficiency payments of $4 million associated with certain guaranteed shipping contracts were deferred during the year ended December 31, 2011. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels, or when shipping rights expire unused.
Revenues
Total revenues for the year ended December 31, 2011 were $213.5 million, a $31.5 million increase compared to the year ended December 31, 2010. This is due principally to an overall increase in pipeline shipments, revenues attributable to our November 2011 asset acquisitions, a $4 million increase in previously deferred revenue realized, the effect of annual tariff increases and the HFC crude pipeline revenue settlement. Overall pipeline shipments were up 10% from the year ended December 31, 2010.
Certain related-party pipeline volumes were down during the current year as a result of downtime at HFC’s Navajo refinery following a plant-wide power outage in late January 2011 and the subsequent delay in restoring production to planned levels.
Revenues from our refined product pipelines were $86.2 million, an increase of $9.7 million compared to the year ended December 31, 2010. This is due to a $4.3 million increase in previously deferred revenue realized and an increase in third-party refined product pipeline shipments. Volumes shipped on our refined product pipelines averaged 143.1 thousand barrels per day (“mbpd”) compared to 135 mbpd for 2010.
Revenues from our intermediate pipelines were $21.9 million, an increase of $1 million compared to the year ended December 31, 2010. This reflects $0.8 million in revenues attributable to the Tulsa interconnect pipelines and the effects of a $0.3 million decrease in previously deferred revenue realized. Shipments on our intermediate pipelines increased to an average of 93.4 mbpd compared to 84.3 mbpd for 2010.
Revenues from our crude pipelines were $46.5 million, an increase of $7.5 million compared to the year ended December 31, 2010. This includes $5.5 million in revenues attributable to a crude pipeline revenue settlement with HFC. Volumes on our crude pipelines averaged 161.8 mbpd compared to 144 mbpd for 2010.
Revenues from terminal, tankage and loading rack fees were $58.9 million, an increase of $13.2 million compared to the year ended December 31, 2010. This increase is due principally to $7.1 million in 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 238.1 mbpd compared to 218.5 mbpd for 2010.
Operations Expense
Operations expense for the year ended December 31, 2011 increased by $9.3 million compared to the year ended December 31, 2010. This increase is due principally to operating costs attributable to our recently acquired assets serving HFC’s El Dorado and Cheyenne refineries and an increase in maintenance services and payroll costs during the current year. With respect to our November 2011 asset acquisitions, GAAP accounting requirements required us to recognize an additional $2.3 million in operating costs that relate to the operation of the assets prior to our acquisition.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2011 increased by $2.5 million compared to the year ended December 31, 2010. This increase is due principally to depreciation attributable to our recent asset acquisitions from HFC and capital projects. With respect to our November 2011 asset acquisitions, GAAP accounting requirements required us to recognize an additional $1.4 million in depreciation expense that relate to the operation of the assets prior to our acquisition.
General and Administrative
General and administrative costs for the year ended December 31, 2011 decreased by $1.1 million compared to the year ended December 31, 2010 due to lower professional fees and services.
Equity in Earnings of SLC Pipeline
Our equity in earnings of the SLC Pipeline was $2.6 million and $2.4 million for the year ended December 31, 2011 and 2010, respectively.
Interest Expense
Interest expense for the year ended December 31, 2011 totaled $36 million, an increase of $2 million compared to year ended December 31, 2010. This increase reflects interest on increased debt levels during the current year, partially offset by prior year costs of $1.1 million that relate to the partial settlement of an interest rate swap. Excluding the effects of fair value adjustments to this swap in 2010, our aggregate effective interest rate was 6.7% for the year ended December 31, 2011 compared to 6.8% for 2010.
State Income Tax
We recorded state income taxes of $234,000 and $296,000 for the years ended December 31, 2011 and 2010, respectively, which are solely attributable to the Texas margin tax.
Results of Operations – Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
Summary
Income from continuing operations for the year ended December 31, 2010 was $58.9 million, a $12.6 million increase compared to the year ended December 31, 2009. This increase in overall earnings was due principally to earnings attributable to our 2009 and March 2010 asset acquisitions and overall increased shipments on our pipeline systems. These factors were partially offset by a decrease in previously deferred revenue realized and increased operating costs and expenses and interest expense.
Revenues for the year ended December 31, 2010 include the recognition of $8.4 million of prior shortfalls billed to shippers in 2009 as they did not meet their minimum volume commitments in any of the subsequent four quarters. Deficiency payments of $10.4 million associated with certain guaranteed shipping contracts were deferred during the year ended December 31, 2010.
Revenues
Total revenues from continuing operations for the year ended December 31, 2010 were $182.1 million, a $35.5 million increase compared to the year ended December 31, 2009. This increase was due principally to revenues attributable to our 2010 asset acquisitions and higher tariffs on affiliate shipments, partially offset by a $7.3 million decrease in previously deferred revenue realized. For 2010, overall pipeline shipments were up 7%, reflecting increased affiliate volumes attributable to HFC’s first quarter of 2009 Navajo refinery expansion, including volumes shipped on our new 16-inch intermediate and Beeson pipelines, partially offset by a decrease in third-party shipments. Additionally, prior year affiliate shipments reflect lower volumes as a result of production downtime during a major maintenance turnaround of the Navajo refinery during the first quarter of 2009. Overall terminal and loading rack volumes also were also up in 2010, increasing 39% over 2009 levels due principally to volumes transferred and stored at our Tulsa storage and rack facilities.
Revenues from our refined product pipelines were $76.4 million, a decrease of $4.7 million compared to the year ended December 31, 2009. This decrease was due principally to an $8.5 million decrease in previously realized deferred revenue that was offset partially by an overall increase in refined product pipeline shipments. Volumes shipped on our refined product pipeline system averaged 135 mbpd compared to 131.7 mbpd for the year ended December 31, 2009, reflecting an increase in affiliate shipments, partially offset by a decline in third-party shipments.
Revenues from our intermediate pipelines were $21 million, an increase of $4.6 million compared to the year ended December 31, 2009. This increase was due principally to increased shipments on our intermediate pipeline system combined with a $1.2 million increase in previously deferred revenue realized. Volumes shipped on our intermediate product pipeline system increased to an average of 84.3 mbpd compared to 69.8 mbpd for 2009.
Revenues from our crude pipelines were $38.9 million, an increase of $9.7 million compared to the year ended December 31, 2009. This increase was due principally to an $8.4 million year-over-year increase in revenues attributable to our Roadrunner Pipeline agreement. Volumes shipped on our crude pipeline system increased to an average of 144 mbpd compared to 137.2 mbpd for 2009.
Revenues from terminal, tankage and loading rack fees were $45.7 million, an increase of $25.9 million compared to the year ended December 31, 2009. This included a $24.7 million year-over-year increase in revenues attributable to volumes transferred and stored at our Tulsa storage and rack facilities. Refined products terminalled in our facilities increased to an average of 218.5 mbpd compared to 156.6 mbpd for 2009.
Operations Expense
Operations expense for the year ended December 31, 2010 increased by $8.9 million compared to the year ended December 31, 2009. This increase was due principally to costs attributable to overall higher throughput volumes, including those from our recent asset acquisitions, and higher maintenance and payroll costs.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2010 increased by $4 million compared to the year ended December 31, 2009. This increase was attributable to our 2009 and March 2010 asset acquisitions and capital projects. Additionally, effective January 1, 2010, we revised the estimated useful lives of our terminal assets to 16 to 25 years resulting in a $3 million reduction in depreciation expense for the year ended December 31, 2010.
General and Administrative
General and administrative costs for the year ended December 31, 2010 of $7.7 million were relatively flat compared to $7.6 million for the year ended December 31, 2009.
Equity in Earnings of SLC Pipeline
Our equity in earnings of the SLC Pipeline was $2.4 million and $1.9 million for the years ended December 31, 2010 and 2009, respectively.
SLC Pipeline Acquisition Costs
We incurred a $2.5 million finder’s fee in connection with the acquisition our SLC Pipeline joint venture interest in March 2009. As a result of accounting requirements effective January 1, 2009, we were required to expense rather than capitalize these direct acquisition costs.
Interest Expense
Interest expense for the year ended December 31, 2010 totaled $34 million, an increase of $12.5 million compared to the year ended December 31, 2009. This increase was due to interest on our 8.25% senior notes and costs of $1.1 million from a partial settlement of an interest rate swap. For the years ended December 31, 2010 and 2009, fair value adjustments to our interest rate swaps resulted in $1.5 million and $0.2 million, respectively, in non-cash interest expense. Excluding the effects of these fair value adjustments, our aggregate effective interest rate was 6.8% for the year ended December 31, 2010 compared to 5.3% for 2009.
State Income Tax
We recorded state income taxes of $296,000 and $20,000 for the years ended December 31, 2010 and 2009, respectively, which are solely attributable to the Texas margin tax. State income taxes for the year ended December 31, 2009 are presented net of a $167,000 tax refund resulting from over-estimates of prior year margin taxes.
Discontinued Operations
We sold our interest in Rio Grande on December 1, 2009. Income from discontinued operations for the year ended December 31, 2009 included a gain from the sale of our 70% interest in Rio Grande of $14.5 million. Rio Grande operations generated earnings of $6.9 million for the year ended December 31, 2009, presented net of earnings attributable to noncontrolling interest holders of $1.6 million.
LIQUIDITY AND CAPITAL RESOURCES
Overview
At December 31, 2011 we had a $275 million senior secured revolving credit agreement expiring in February 2016 (the “Credit Agreement”). During the year ended December 31, 2011, we received advances totaling $118 million and repaid $77 million, resulting in net borrowings of $41 million under the Credit Agreement and an outstanding balance of $200 million at December 31, 2011.
On February 3, 2012, we amended the Credit Agreement, increasing the size of the credit facility from $275 million to $375 million. The Amended Credit Agreement expires in February 2016 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 and to fund distributions to unitholders up to a $30 million sub-limit.
If any particular lender under the Amended 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 Amended 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 $781 million 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 Amended Credit Agreement will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future.
In February, May, August and November 2011, we paid regular quarterly cash distributions of $0.845, $0.855, $0.865 and $0.875, respectively, on all units, an aggregate amount of $91.5 million. Included in these distributions was $13.7 million paid to the general partner as incentive distributions.
Cash and cash equivalents increased by $2.9 million during the year ended December 31, 2011. The cash flows provided by operating activities of $93.1 million exceeded the combined cash flows used for investing and financing activities of $39.3 million and $50.9 million, respectively. Working capital increased by $20.1 million to $12.3 million at December 31, 2011 from a deficit of $7.8 million at December 31, 2010.
Cash Flows - Operating Activities
Year Ended December 31, 2011 Compared with Year Ended December 31, 2010
Cash flows from operating activities decreased by $10.1 million from $103.2 million for the year ended December 31, 2010 to $93.1 million for the year ended December 31, 2011. This decrease is due principally to payments attributable to increased interest and operating expenses, net of $11.1 million in additional cash collections from our customers.
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 $10.4 million during the year ended December 31, 2010 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the year ended December 31, 2011. We recognized an additional $2 million related to shortfalls billed in 2011 as a result of an amendment to our throughput agreement with Alon in June 2011 that limits the carryover term of credits attributable to such shortfall billings to the calendar year end in which the shortfalls occurred. Another $0.8 million was included in our accounts receivable at December 31, 2011 related to shortfalls that occurred in the fourth quarter of 2011.
Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
Cash flows from operating activities increased by $35 million from $68.2 million for the year ended December 31, 2009 to $103.2 million for the year ended December 31, 2010. This increase is due principally to $38 million in additional cash collections from our major customers, resulting from increased revenues, partially offset by year-over-year changes in payments attributable to costs of increased operations and interest.
MANAGEMENT DISCUSSION FOR LATEST QUARTER
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 the refining and marketing operations of HollyFrontier Corporation (“HFC”) in the Mid-Continent, Southwest and Rocky Mountain regions of the United States. HFC currently owns a 42% interest in us including the 2% general partnership interest.
We also own and operate refined product pipelines and terminals, located primarily in Texas, that service Alon’s (“Alon”) refinery in Big Spring, Texas. Additionally, we own a 25% joint venture interest in the SLC Pipeline (the “SLC Pipeline”), a 95-mile intrastate crude oil pipeline system that serves refineries in the Salt Lake City 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.
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 3,807,615 of our common units.
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. These minimum annual payments or revenues are subject to annual tariff rate adjustments on July 1, based on the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of March 31, 2012 , these agreements with HFC will result in minimum annualized payments to us of $191.8 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 also 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 subject to annual tariff rate adjustments. Additionally, we have a capacity lease agreement with Alon under which we lease Alon space on our Orla to El Paso pipeline for the shipment of refined product. The terms under this agreement expire beginning in 2018 through 2022. As of March 31, 2012 , these agreements with Alon will result in minimum annualized payments to us of $30.9 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 (“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. This fee does not include the salaries of pipeline and terminal personnel 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.
Results of Operations—Three Months Ended March 31, 2012 Compared with Three Months Ended March 31, 2011
Summary
Net income for the three months ended March 31, 2012 was $22.0 million , a $6.8 million increase compared to the three months ended March 31, 2011 . This increase in earnings is due principally to increased pipeline shipments, earnings attributable to our recent acquisitions and annual tariff increases. These factors were offset partially by a decrease in previously deferred revenue realized, increased operating costs and expenses and a loss incurred on the early extinguishment of certain long-term debt.
Revenues for the three months ended March 31, 2012 include the recognition of $1.7 million of prior shortfalls billed to shippers in 2011. Deficiency payments of $1.1 million associated with certain guaranteed shipping contracts were deferred during the three months ended March 31, 2012 . Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels, or when shipping rights expire unused.
Revenues
Total revenues for the three months ended March 31, 2012 were $63.5 million , an $18.5 million increase compared to the three months ended March 31, 2011 . This is due principally to overall increased pipeline shipments, revenues attributable to our November 2011 asset acquisitions and the effect of annual tariff increases, partially offset by a $2.4 million decrease in previously deferred revenue realized.
Overall pipeline volumes were up 33% compared to the three months ended March 31, 2011. During the first quarter of 2011, related-party throughput volumes were below target levels due to production downtime at HFC's Navajo refinery following a plant-wide power outage in January 2011.
Revenues from our refined product pipelines were $20.7 million , an increase of $1.7 million compared to the three months ended March 31, 2011 . This includes the effects of a $2.4 million decrease in previously deferred revenue realized. Volumes shipped on our refined product pipelines averaged 161.5 thousand barrels per day ("mbpd") compared to 125.7 mbpd for the same period last year.
Revenues from our intermediate pipelines were $7.0 million , an increase of $2.4 million compared to the three months ended March 31, 2011 . This includes $1.2 million in revenues attributable to the Tulsa interconnect pipelines which commenced operations in September 2011, and a $0.5 million increase in previously deferred revenue realized. Volumes shipped on our intermediate pipelines averaged 123.6 mbpd compared to 68.6 mbpd for the same period last year.
Revenues from our crude pipelines were $10.5 million , an increase of $1.2 million compared to the three months ended March 31, 2011 . Volumes shipped on our crude pipelines increased to an average of 153.7 mbpd compared to 136.3 mbpd for the same period last year.
Revenues from terminal, tankage and loading rack fees were $25.2 million , an increase of $13.2 million compared to the three months ended March 31, 2011 . This increase is due principally to $11.7 million in 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 314.6 mbpd compared to 198.3 mbpd for the same period last year.
Operations Expense
Operations expense for the three months ended March 31, 2012 increased by $4.2 million compared to the three months ended March 31, 2011 . This increase is due principally to operating costs attributable to our recently acquired assets serving HFC's El Dorado and Cheyenne refineries of $1.4 million and year-over-year increases in first quarter maintenance service and payroll costs.
Depreciation and Amortization
Depreciation and amortization for the three months ended March 31, 2012 increased by $2.6 million compared to the three months ended March 31, 2011 . This increase is due principally to depreciation attributable to our recent asset acquisitions from HFC of $1.0 million and capital projects.
General and Administrative
General and administrative costs for the three months ended March 31, 2012 increased by $0.7 million compared to the three months ended March 31, 2011 due to higher professional fees related to our recent transactions.
Equity in Earnings of SLC Pipeline
Our equity in earnings of the SLC Pipeline was $0.8 million for the three months ended March 31, 2012 compared to $0.7 million for the three months ended March 31, 2011 .
Interest Expense
Interest expense for the three months ended March 31, 2012 totaled $10.4 million , an increase of $1.9 million compared to the three months ended March 31, 2011 . This increase reflects interest on a year-over-year increase in debt levels. Our aggregate effective interest rate was 7.9% for the three months ended March 31, 2012 compared to 6.8% for the same period of 2011 .
Loss on Early Extinguishment of Debt
We recognized a charge of $2.6 million upon the early extinguishment of our 6.25% senior notes for the three months ended March 31, 2012 . This charge relates to the premium paid to note holders upon their tender of an aggregate principal amount of $157.8 million and related financing costs that were previously deferred.
State Income Tax
We recorded state income taxes of $75,000 and $ 228,000 for the three months ended March 31, 2012 and 2011, respectively, which are solely attributable to the Texas margin tax.
LIQUIDITY AND CAPITAL RESOURCES
Overview
We have a $375 million senior secured revolving credit facility expiring in February 2016 (the “Credit Agreement”) that is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. Also it is available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $30 million sub-limit. In February 2012 we amended our previous credit agreement increasing the size of the credit facility from $275 million to $375 million .
During the three months ended March 31, 2012 , we received advances totaling $36.0 million and repaid $81.0 million , resulting in net repayments of $45.0 million under the Credit Agreement. There was an outstanding balance of $155.0 million at March 31, 2012 .
Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the ability to raise up to $781.0 million 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, we paid regular quarterly cash distributions of $0.885 on all units in an aggregate amount of $29.7 million . Included in these distributions were $4.9 million of incentive distribution payments to the general partner.
Cash and cash equivalents increased by $9.1 million during the three months ended March 31, 2012 . The cash flows provided by operating activities of $28.2 million exceeded the combined cash flows used for investing and financing activities of $6.3 million and $12.8 million , respectively. Working capital decreased by $11.5 million to $0.8 million at March 31, 2012 from $12.3 million at December 31, 2011 .
Cash Flows—Operating Activities
Cash flows from operating activities increased by $13.0 million from $15.2 million for the three months ended March 31, 2011 to $28.2 million for the three months ended March 31, 2012 . This increase is due principally to $18.5 million in additional cash collections from our customers, partially offset by payments attributable to increased interest and 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 $1.7 million during the three months ended March 31, 2011 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the three months ended March 31, 2012 . Another $1.1 million is included in our accounts receivable at March 31, 2012 related to shortfalls that occurred during the first quarter of 2012 .
Cash Flows—Investing Activities
Cash flows used for investing activities decreased by $5.1 million from $11.5 million for the three months ended March 31, 2011 to $6.3 million for the three months ended March 31, 2012 . During the three months ended March 31, 2012 and 2011 , we invested $6.3 million and $11.5 million in additions to properties and equipment, respectively.
Cash Flows—Financing Activities
Cash flows used for financing activities were $12.8 million for the three months ended March 31, 2012 compared to $2.6 million for the three months ended March 31, 2011 , an increase of $10.1 million . During the three months ended March 31, 2012 , we received $36.0 million and repaid $81.0 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 $157.8 million and $72.9 million of our 6.25% senior notes and promissory notes, respectively. Additionally, we paid $29.7 million in regular quarterly cash distributions to our general and limited partners, paid $1.1 million in financing costs to amend our previous credit agreement and paid $1.3 million for the purchase of common units for recipients of our incentive grants. During the three months ended March 31, 2011 , we received $30.0 million and repaid $7.0 million in advances under the Credit Agreement. Additionally, we paid $22.2 million in regular quarterly cash distributions to our general and limited partners, incurred $3.0 million in financing costs upon the issuance of the 8.25% Senior Notes, and paid $0.4 million for the purchase of common units for recipients of our incentive grants.
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 consist of maintenance capital expenditures and expansion capital expenditures. 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 Holly Logistic Services, L.L.C. (“HLS”) board 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, special 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 2012 capital budget is comprised of $8.9 million for maintenance capital expenditures and $25.8 million for expansion capital expenditures.
We recently have made certain modifications to our crude oil gathering and trunk line system that effectively have increased our ability to gather and transport an additional 10,000 bpd of Delaware Basin crude oil in response to increased drilling activity in southeast New Mexico. Furthermore, we have developed a project to replace a 5 -mile section of this pipeline system that will allow for an additional 15,000 bpd of capacity that will be executed as needed if Delaware Basin crude volumes continue to increase. This project is estimated to cost approximately $2.0 million . We have a second project that consists of the reactivation and conversion to crude oil service of a 70 -mile, 8- inch petroleum products pipeline owned by us. Once in service, this pipeline will initially be capable of transporting up to 35,000 bpd of crude oil from southeast New Mexico to third-party common carrier pipelines in west Texas for further transport to major crude oil markets. The scope of this project is being finalized. Subject to receipt of acceptable shipper support and board approval, this project could be operational in early 2013.
We are in discussions with HFC regarding our option to purchase its 75 % equity interest in the UNEV Pipeline, a joint venture pipeline that is capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada. The initial capacity of this pipeline is 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The total construction cost of this pipeline, including terminals, ethanol blending and storage facilities, was approximately $410.0 million. HFC's share of the cost is $ 308.0 million . The pipeline was mechanically complete in November 2011, and initial start-up activities commenced in December 2011. We are not obligated to purchase the UNEV Pipeline nor are we subject to any fees or penalties if HLS' board of directors decides not to proceed with this opportunity.
We expect that our currently planned sustaining and maintenance capital expenditures, as well as expenditures for acquisitions and capital development projects such as our option to purchase HFC’s interest in the UNEV Pipeline described above, 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 fund some of these capital projects, especially the UNEV Pipeline, may be limited.
Credit Agreement
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.
The Credit Agreement imposes certain requirements on us 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 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 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 $294.8 million in net proceeds from the issuance were used to fund $157.8 million aggregate principal amount of 6.25% senior notes tendered pursuant to a cash tender offer and consent solicitation announced in February 2012, to repay $72.9 million in Promissory Notes due to HFC as discussed below, related fees, expenses and accrued interest in connection with these transactions and to repay borrowings under the Credit Agreement.
In April 2012, we called for redemption $27.2 million aggregate principal amount of 6.25% senior notes that remained outstanding following the cash tender offer and consent solicitation.
In March 2010, we issued $150 million in aggregate principal amount outstanding of 8.25% senior notes maturing March 15, 2018. A portion of the $147.5 million in net proceeds from the issuance was used to fund our $93.0 million purchase of the Tulsa and Lovington storage assets from HFC on March 31, 2010. Additionally, we used a portion to repay $42.0 million in outstanding Credit Agreement borrowings, with the remaining proceeds available for general partnership purposes, including working capital and capital expenditures.
Our 6.5% senior notes and 8.25% senior notes (collectively, the “Senior Notes”) are unsecured and impose certain restrictive covenants which we are subject to and currently in compliance with, 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 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.
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 certain tankage, loading rack and crude receiving 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.
Contractual Obligations
In February 2012, we amended our previous credit agreement increasing the size of the credit facility from $275 million to $375 million. The Credit Agreement expires in February 2016. During the three months ended March 31, 2012 , we repaid net advances of $45.0 million resulting in $155.0 million of outstanding borrowings under the Credit Agreement at March 31, 2012 .
In March 2012, we issued $300 million in aggregate principle amount of 6.5% senior notes maturing March 2020.
There were no other significant changes to our long-term contractual obligations during this period.
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 three months ended March 31, 2012 and 2011 . Historically, the PPI has increased an average of 3.6% 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 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 in 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 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 with HFC, HFC has agreed to indemnify us, subject to certain limitations, for environmental noncompliance and remediation liabilities associated with assets transferred to us from HFC and occurring or existing prior to the date of such transfers. The Omnibus Agreement provides environmental indemnification with respect to certain transferred assets of up to $15 million through 2021, plus additional indemnification of $2.5 million through 2015 for certain of these assets and up to $7.5 million through 2023 for certain other assets. HFC’s indemnification obligations under the Omnibus Agreement do not apply to (i) the Tulsa west loading racks acquired in August 2009, (ii) the 16 -inch intermediate pipeline acquired in June 2009, (iii) the Roadrunner Pipeline, (iv) the Beeson Pipeline, (v) the logistics and storage assets acquired from Sinclair in December 2009, or (vi) the Tulsa east storage tanks and loading racks acquired in March 2010. For the Tulsa loading racks acquired from HFC in August 2009 and the Tulsa logistics and storage assets acquired from Sinclair in December 2009, HFC agreed to indemnify us for environmental liabilities arising from our pre-ownership operations of these assets. Additionally, HFC agreed to indemnify us for any liabilities arising from its operation of our loading racks located at HFC's Tulsa refinery west facility.
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 through 2015, subject to a $100,000 deductible and a $20 million maximum liability cap.
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 March 31, 2012 , we have an accrual of $1.1 million that relates to environmental clean-up projects for which we have assumed liability. 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. Our significant accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Operations—Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2011 . Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements include revenue recognition, assessing the possible impairment of certain long-lived assets and goodwill, and assessing contingent liabilities for probable losses. There have been no changes to these policies in 2012 . We consider these 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.
New Accounting Pronouncements
Presentation of Comprehensive Income
Effective January 1, 2012, we adopted the accounting standard update that requires the presentation of net income and other comprehensive income in one continuous statement or in two separate, but consecutive, statements and eliminated the option to present the components of other comprehensive income in the statement of partners' equity.
Intangibles-Goodwill and Other: Testing Goodwill for Impairment
Effective January 1, 2012, we adopted the accounting standard update that allows entities an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. Under this option, we no longer are required to calculate the fair value of a reporting unit unless we determine, based on that qualitative assessment, that it is more likely than not that the reporting unit's fair value is less than its carrying amount. The adoption of this accounting standard did not have an impact on our financial condition, results of operations and cash flows.
RISK MANAGEMENT
We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.
As of March 31, 2012 , we have an interest rate swap, designated as a cash flow hedge, that hedges our exposure to the cash flow risk caused by the effects of LIBOR changes on a $155.0 million Credit Agreement advance. This 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 currently 2.25% , which equaled an effective interest rate of 3.24% as of March 31, 2012 . This swap contract matures in February 2016.
We review publicly available information on our counterparty in order to review and monitor its financial stability and assess its ongoing ability to honor its commitments under the interest rate swap contract. This counterparty is a large financial institution. Furthermore, we have not experienced, nor do we expect to experience, any difficulty in the counterparty honoring its respective commitment.
The market risk inherent in our debt positions is the potential change arising from increases or decreases in interest rates as discussed below.
At March 31, 2012 , 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 would generally affect the fair value of the Senior Notes, but not our earnings or cash flows. At March 31, 2012 , the fair values of our 6.5% Senior Notes and 8.25% Senior Notes were $305.3 million and $161.3 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 March 31, 2012 would result in a change of approximately $11.7 million and $5.1 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 March 31, 2012 , borrowings outstanding under the Credit Agreement were $155.0 million . By means of our cash flow hedge, we have effectively converted the variable rate on $155.0 million of outstanding borrowings to a fixed rate of 3.24% .
At March 31, 2012 , our cash and cash equivalents included highly liquid investments with a maturity of three months or less at the time of purchase. Due to the short-term nature of our cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected by the effect of a sudden change in market interest rates on our investment portfolio.
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.
CONF CALL
Neale Hickerson
Well, good afternoon, everyone, and welcome to Holly Energy Partners first quarter earnings webcast conference call. I’m Neale Hickerson, Vice President of Investor Relations at HEP. With us this afternoon from HEP are Matt Clifton, Chairman and CEO; David Blair, President; Bruce Shaw, our Senior Vice President and Chief Financial Officer; Steve Wise, Vice President and Treasurer; and Scott Surplus, Vice President and Controller.
This morning we issued a press release announcing results for our first quarter year-end 2010. This press release can be found on our website at www.hollyenergy.com. For this afternoon call, Bruce Shaw will begin with some comments regarding our financial performance. David Blair will then follow up with some additional prepared remarks. And at the conclusion of these prepared remarks and comments, our team will be available for your questions.
Before we turn things over to Bruce and David for their comments, we are required to make the following Safe Harbor disclosure statement. Also please note our Safe Harbor statement in our press release from this morning. The following is the Safe Harbor statement under the Private Securities Litigation Reform Act of 1995
The statements in our conference call today related to matters that are not historical facts are forward-looking statements within the meaning of federal securities laws.
These statements are based on our beliefs and assumptions using currently available information and expectations and are not guarantees of future performance and do involve certain risks and uncertainties, including those which we have noted in the Safe Harbor portion of our press release today and in our filings which we make with the Securities and Exchange Commission.
Also please note that these forward-looking statements speak only as of today, April 29, 2010, and any time sensitive information provided may no longer be accurate at the time of any webcast replay or your reading of the transcript of our call. Other than as required by law, we assume no obligation to publicly update or revise such statements, whether as a result of new information, future events or otherwise.
Lastly, please note that on the call today, we may have a discussion of non-GAAP financial measures that we use in analyzing our financial results. Please refer to today’s press release for required reconciliations to GAAP financial measures and other related disclosures or information on where you may find them.
And now I’d like to turn things over to Bruce Shaw.
Bruce Shaw
Thank you, Neale. And good afternoon, everyone. On April 23, 2010, we announced an increase in our distribution to $0.815 per unit, which is a 5% increase over the $0.775 per unit we declared for the same quarter last year.
As you’ve seen from our press release this morning, our distributable cash flow for the first quarter ended on March 31 was $20.2 million, up $5.6 million or 38% from the same period last year. The increase in distributable cash flow resulted primarily from contributions from our 2009 acquisitions, though volumes on our heritage pipeline systems were lower than the recent quarterly levels due to scheduled project work in our Navajo refinery.
Our income for the quarter was $10.7 million or $0.36 per unit versus $5.4 million or $0.25 per unit for the same period last year. Revenues increased compared to first quarter ’09 again due to our 2009 acquisitions. But we are below expected go-forward quarterly run rate due to the planned downtime at Navajo and lower third-party shipments.
We recognize slightly less deferred revenue this quarter than we did during last year’s first quarter. Deferred revenue recognized results from shortfall billings in prior quarters, for which clawback rights were used or expired. As a reminder, the payments we received from Holly and Alon for quarterly shortfall billings under their minimum commitments are included in distributable cash flow in the current accounting period but classified as deferred revenues are not recognized on our income statement until such time that they can be recognized, which is typically four quarters later.
Our current minimum commitments from our major customers are approximately $160 million per year or $40 million per quarter. For the remainder of 2010, revenues should be in the $45 million range per quarter. Operating expenses other than depreciation and amortization of approximately $13.1 million for the quarter were $2.7 million higher than last year’s first quarter due to increased throughput volumes, higher payroll, and higher maintenance expense, mostly related to our 2009 acquisitions. Going forward, incorporating recent acquisitions, the normal run rate should be in the $13 million to $13.5 million per quarter range.
G&A expenses were $1.2 million higher than last year’s first quarter number and also above the normal run rate due primarily to professional expenses related to recently completed acquisitions. The normal run rate for G&A should be less than $2 million per quarter. Compared to the first quarter of ’09, we had a $0.6 million decrease in deferred revenue recognized.
Shortfalls build for the first quarter 2010 for shipments below committed volumes was $3.6 million, including $1.2 million for affiliate pipelines and $2.4 million for third-party pipelines. Offsetting this amount and recognized as revenue were total forfeitures at $2.5 million from first quarter 2009, including $1.8 million for affiliate pipeline shipments and $0.7 million for third-party pipeline movements.
On March 31, 2010, we had $9.5 million in deferred revenue on the balance sheet. These deferrals will be recognized in revenue over the course of the next four quarters as the shippers’ contractual clawback rights are either utilized or expired. The deferred revenue increase in the second quarter of 2009, for which clawback rights expire on June 30, 2010 or during the second quarter of this year, was approximately $1.6 million. This is about $4 million less than was recognized in the second quarter of ’09, since the second quarter of ’09 included revenue recognition generated during Alon’s significant downtime in 2008.
EBITDA for the quarter was $25.5 million, benefiting from previously discussed acquisitions compared to last year’s first quarter. But at this level, it was lower than we expect for our future quarterly run rate because of lower heritage pipeline volumes due to planned work at Holly’s Navajo refinery. Going forward, we would expect quarterly EBITDA to be in the $30 million to $35 million range per quarter.
The total distribution will amount to approximately $20.9 million and will be paid on May 14, 2010 to unit holders of record as of May 4, 2010. At March 31, we had $335 million of senior notes outstanding and $171 million drawn under our $300 million credit facility. Recall that we issued $150 million of 8.25% senior notes in early March to fund our recent $93 million acquisition of storage and loading facilities from Holly Corporation. The excess proceeds were used to pay down our revolving credit facility and for general partnership purposes.
Now, I think David has a few comments before we turn things over to questions. David?
David Blair
Thanks, Bruce. Thank you, everyone, for listening to the call today. We are very pleased with our year-over-year growth and our position for the balance of 2010. We continued to add to our logistics asset portfolio with the acquisition of an additional 2.1 million barrels of storage and a rail loading rack at Holly's Tulsa refinery during the quarter, as well as (inaudible) loading rack at Holly’s Lovington, New Mexico facility. These acquisitions should add to our revenues about $13.8 million per year.
Pipeline volumes during the quarter on our systems were lower than anticipated due to downtime for maintenance in our larger customers’ facilities although distributable cash flow remained strong as a result of our minimum revenue contracts. Pipeline volumes have returned to expected levels during April. Our first quarter operating expenses were higher than we had planned, resulting from increased expenses related to the Tulsa acquisition, unplanned tank maintenance, and an environmental accrual cost. We expect our operating expenses to level out the remainder of the year.
Maintenance capital expenditures were about 50% as expected due to project timing. We anticipate catching up the next three quarters to around $5.5 million total spend for 2010. We have completed all major expansion projects around our New Mexico operations and currently have WTS crude oil in the Roadrunner and Lovington to Artesia pipelines.
We are working on expansion pipelines. We are working on expansion pipeline projects connecting Holly’s Tulsa facility as well as ethanol blending upgrades at our Tulsa rack. We are also evaluating expansion to our crude oil gathering at current volumes in Southeast New Mexico.
As we look to the future, we continue to be excited about the UNEV project, which should start construction on the pipeline in June of 2010. We also continue to evaluate third-party acquisitions that come about in the marketplace. We are pleased to have increased our distribution to $0.815 a unit per quarter, a $3.26 a unit on a full year basis. We are very proud of our track record of 22 consecutive increases. We plan to continue to prudently growing our business to provide additional increases in the future.
I’ll turn it back to Neale.
Neale Hickerson
And I’d like to turn it back over to Christie. Christie, if you could repeat the process to ask a question, we’ll move to that part of our call.
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