UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2013
or
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 001-35230
Oiltanking Partners, L.P.
(Exact name of registrant as specified in its charter)
Delaware | 45-0684578 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
333 Clay Street, Suite 2400 Houston, TX | 77002 | |
(Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code: (281) 457-7900
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered |
Common units representing limited partnership interests | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer | o | Accelerated filer | þ | |
Non-accelerated filer | o | Smaller reporting company | o | |
(Do not check if a smaller reporting company) | ||||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ
The aggregate market value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the common units outstanding, for this purpose, as if they may be affiliates of the registrant) was approximately $580.5 million on June 28, 2013, based on a closing price of $50.80 per common unit as reported on the New York Stock Exchange on such date.
As of February 20, 2014, there were 22,049,901 common units and 19,449,901 subordinated units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None.
TABLE OF CONTENTS
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
The information contained in this Annual Report on Form 10-K (this “Report”) includes “forward-looking statements.” All statements that express belief, expectation, estimates or intentions, as well as those that are not statements of historical facts, are forward-looking statements. Such statements use forward-looking words such as “proposed,” “anticipate,” “project,” “potential,” “could,” “should,” “continue,” “estimate,” “expect,” “may,” “believe,” “will,” “plan,” “seek,” “outlook” and other similar expressions that are intended to identify forward-looking statements, although some forward-looking statements are expressed differently. These statements discuss future expectations and contain projections. Specific factors that could cause actual results to differ from those in the forward-looking statements include, but are not limited to: (i) adverse regional, national or international economic conditions, adverse capital market conditions or adverse political developments; (ii) changes in the marketplace for our products or services, such as increased competition, better energy efficiency, or general reductions in demand; (iii) changes in the long-term supply and demand of crude oil, refined petroleum products and liquefied petroleum gas (“LPG”) in the markets in which we operate, as well as the supply and demand economics relating to the products imported or exported across our docks; (iv) actions taken by our customers, competitors and third party operators; (v) nonpayment by our customers or nonperformance by our contractors; (vi) changes in the availability and cost of capital; (vii) unanticipated capital expenditures in connection with the construction, repair, or replacement of our assets; (viii) operating hazards, natural disasters, terrorism, weather-related delays, adverse weather conditions, including hurricanes, natural disasters, environmental releases, casualty losses and other matters beyond our control that interrupt our operations; (ix) the effects of existing and future laws and governmental regulations to which we are subject, including environmental regulations and tax regulations that permit the treatment of us as a partnership for federal income tax purposes; and (x) the effects of future litigation. These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors that could also have material adverse effects on future results include the known material risks and uncertainties under the captions “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Report. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements, and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to or effect on us or our business or operations.
The forward-looking statements contained in this Report speak only as of the date hereof. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this Report and in our future periodic reports filed with the U.S. Securities and Exchange Commission (“SEC”). In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Report may not occur.
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PART I
Item 1. Business
Introduction
We are a publicly traded Delaware limited partnership. Our common units are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “OILT.” We were formed by Oiltanking Holding Americas, Inc. (“OTA”) in 2011 to engage in the independent terminaling, storage and transportation of crude oil, refined petroleum products and LPG. Through our wholly owned subsidiaries, Oiltanking Houston, L.P. (“OTH”) and Oiltanking Beaumont Partners, L.P. (“OTB”), we own and operate terminaling and storage assets located along the United States Gulf Coast on the Houston Ship Channel and in Beaumont, Texas. We report in one business segment. See “Item 8. Financial Statements and Supplementary Data” for revenues from external customers, measures of profit and total assets.
We provide services to major integrated oil companies, distributors, marketers and chemical and petrochemical companies, typically under long-term commercial agreements that include minimum volume commitments and inflation escalators. We do not take ownership of the crude oil, refined products or LPG that we terminal, store or transport nor do we engage in any marketing or trading of commodities.
Within the energy industry, midstream storage and terminaling services are the critical logistical link between oil and gas producers and the refining and petroleum sector. The diagram below illustrates the key position and function of independent terminaling and storage providers like us within the crude oil and refined products supply chain.
Crude Oil and Petroleum Products Supply Chain
At December 31, 2013, we had nearly 22 million barrels of total active storage capacity at our Houston and Beaumont terminals. These integrated facilities are strategically located and directly connected to 23 key refining, production and storage facilities along the Gulf Coast and the Cushing, Oklahoma storage interchange through dedicated and common carrier pipelines. In addition, our facilities provide our customers deep-water access and international distribution capabilities. Our Houston terminals serve as a regional hub for crude oil and other feedstocks for refineries and petrochemical facilities located in the Gulf Coast region and also serve as important export facilities for LPG, crude oil and other refined petroleum products. Our Beaumont terminal serves as a regional hub for refined petroleum products for refineries located in the Gulf Coast region.
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Organizational Structure and History
The following chart depicts our simplified ownership structure as of December 31, 2013.
We completed our initial public offering (“IPO”) on July 19, 2011. In exchange for OTA and its affiliates contributing all of their equity interests in OTH and OTB to us, we issued limited partner interests to OTA and its affiliates. We also issued incentive distribution rights (“IDRs”) to our general partner. Prior to the completion of the IPO, OTH and OTB were wholly owned subsidiaries of OTA.
OTA owns and controls OILT’s general partner, OTLP GP, LLC. OTA is a wholly owned subsidiary of our German parent company, Oiltanking GmbH, one of the world’s leading independent storage providers for crude oil, refined petroleum products, liquid chemicals and gases. Oiltanking GmbH and its subsidiaries, other than OILT and its subsidiaries, are collectively referred to herein as the “Oiltanking Group.” As used in this document, the terms “we,” “us,” and “our” and similar terms refer to OILT and its subsidiaries, where applicable, unless the context indicates otherwise.
At December 31, 2013, we had outstanding (i) 22,049,901 common units and 19,449,901 subordinated units representing limited partner interests, (ii) a 2.0% general partner interest and (iii) IDRs. OTA and its affiliates own 7,949,901 common units and 19,449,901 subordinated units, representing 66.0% of all of our outstanding common and
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subordinated units (or a 64.7% limited partner interest), and other security holders hold 14,100,000 common units, representing the remaining 34.0% (or a 33.3% limited partner interest). The limited partners collectively hold a 98.0% limited partner interest in OILT, and the general partner holds a 2.0% general partner interest and all of OILT’s IDRs.
2013 and Recent Developments
Expansion Projects and Assets Placed Into Service
In November 2011, we announced approval of expansion projects of approximately $85.0 million to construct two new crude oil pipelines along the Houston Ship Channel and approximately 1.1 million barrels of new crude oil storage capacity at our Houston terminal. During the first quarter of 2012, the board of directors of our general partner approved an additional $11.0 million of spending to extend the pipeline to a third-party terminal in Houston. During January 2013, we placed this pipeline expansion project into service. In February 2013, we placed three new crude oil storage tanks with a total capacity of 825,000 barrels into service and in July 2013, we placed the final 275,000 barrel tank of the four-tank expansion project into service at our Houston terminal.
In Beaumont, during the first quarter of 2013, we placed into service two new refined products storage tanks with total capacity of 320,000 barrels.
Appelt Expansion Projects
In April 2012, we announced approval of our “Appelt I” expansion project, a $104.0 million project to construct approximately 3.2 million barrels of new crude oil storage capacity near our Houston terminal at our Appelt property. During 2013, as part of our Appelt I expansion, we placed into service nine new crude oil storage tanks with a total capacity of 2,970,000 barrels. In January 2014, we completed the Appelt I project by placing the remaining storage tank with a total capacity of 210,000 barrels into service.
In September 2012, we announced approval of our “Appelt II” expansion project, a $70.0 million project to construct approximately 3.3 million barrels of new crude oil storage capacity, adjacent to our ongoing Appelt I project. This additional storage capacity is expected to be placed into service during the third and fourth quarters of 2014.
In November 2013, we announced approval of expansion projects of approximately $101.0 million to construct approximately 3.5 million barrels of additional crude oil storage capacity near our Houston terminal at our Appelt property. One of these projects includes a new 390,000 barrel storage tank to be connected to the Appelt I and Appelt II manifolds that is expected to be completed by the end of 2014. The remaining additional storage capacity of approximately 3.1 million barrels consists of nine tanks to be constructed on 26 acres of land adjacent to our ongoing Appelt II expansion. The 3.1 million barrel project, which we refer to as “Appelt III,” would include a new manifold, and, upon completion, would bring total storage capacity at our Appelt property to approximately 10.0 million barrels. We anticipate commencing construction on Appelt III during the third quarter of 2014 when all relevant permits are in place. The new storage capacity at Appelt III is expected to be placed into service during the fourth quarter of 2015 and first quarter of 2016.
Pipeline Expansion Projects
In November 2013, we announced approval of expansion projects of approximately $98.0 million to construct two new crude oil pipelines connecting our Houston facility with Crossroads Junction, which is the termination point of the Houston lateral of TransCanada Corporation’s Gulf Coast Pipeline from Cushing and the origination point of Shell Pipeline’s Houston-to-Houma pipeline (the “HoHo Pipeline”). The expansion projects include a new 24-inch pipeline that will give our terminal customers direct access to the origination point of the HoHo Pipeline, which is expected to transport crude oil from the Houston area eastbound to refining centers in Texas and Louisiana. The expansion projects also include a new 36-inch pipeline that will give our terminal customers access to the termination point of TransCanada Corporation’s Gulf Coast Pipeline, which is expected to connect to the Keystone XL pipeline if approved and constructed. The 24-inch pipeline is expected to be completed by the end of 2014, and the 36-inch pipeline is expected to be completed by the end of the first quarter of 2015.
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LPG Export Terminal Agreement and Dock Expansion Project
In March 2013, we announced an expansion of our relationship with Enterprise Products Partners L.P. (“Enterprise”) and plans to increase our ability to import and export LPG at our terminal on the Houston Ship Channel. In connection with the agreement with Enterprise, we announced a $44.0 million expansion project to construct a new vessel dock and add infrastructure to existing docks. The dock expansion project is expected to be completed by the end of 2014. Pursuant to this agreement with Enterprise, we were initially entitled to participate in margin sharing with Enterprise on only a portion of the customer vessels loaded at our Houston facility; however, in July 2013, we triggered a contractual provision that entitled us to participate in margin sharing on all customer vessels loaded at our Houston facility after January 2014. We also agreed to provide vessel-based LPG import and export services on the Houston Ship Channel exclusively to Enterprise, and Enterprise agreed to use our facility on an exclusive basis for its vessel-based imports and exports of LPG on the Houston Ship Channel.
In January 2014, we announced a further expansion of our terminal service agreement with Enterprise to handle increased volumes of LPG exports at our Houston terminal. Under the amended agreement, the primary contract term was extended to 50 years from the February 1, 2014 effective date, and the exclusivity provisions relating to the Houston Ship Channel in the prior agreement were expanded to cover all of the U.S. Gulf Coast. The throughput rates and margin sharing provisions in the amended agreement remain unchanged from the prior terminal service agreement.
Loan Agreement
On June 26, 2013, OTH entered into a $50.0 million unsecured loan agreement (the “$50.0 million Loan Agreement”) with Oiltanking Finance B.V. (“OT Finance”) with a maturity date of June 30, 2023. In July 2013, OTH borrowed $50.0 million under this loan agreement, and the proceeds were used to repay outstanding balances under the revolving line of credit agreement with OT Finance (as amended, the “Credit Agreement”). At December 31, 2013, OTH had $50.0 million of outstanding borrowings under this loan agreement at a fixed interest rate of 5.435% per annum. See Note 8 in the Notes to Consolidated Financial Statements for further information.
Equity Issuance
On November 22, 2013, we completed a public offering of 2,600,000 common units at a price to the public of $61.65 per unit. The proceeds from the offering, net of underwriting discounts and other offering expenses, totaled approximately $154.3 million. In connection with the offering, our general partner contributed an additional $3.3 million to us to maintain its 2.0% general partner interest in us. See Note 9 in the Notes to Consolidated Financial Statements for further information.
Services Agreement Fee Adjustment
In August 2013, the Conflicts Committee of the board of directors of our general partner approved a requested increase to the fixed fee charged to us under the services agreement with Oiltanking North America, LLC, a subsidiary of OTA, and our general partner (the “Services Agreement”) from $15.1 million to $18.8 million on an annualized basis to reflect higher selling, general and administrative expenses associated with expansion projects placed in service in 2013. The fee increase was effective as of July 1, 2013. See Note 3 in the Notes to Consolidated Financial Statements for further information.
Management Changes
On July 1, 2013, Jonathan Z. Ackerman was appointed by the board of directors of our general partner to serve as Vice President and Chief Financial Officer of our general partner. Kenneth F. Owen, the previous Vice President and Chief Financial Officer, was named Terminal Manager of our expanding Houston complex and has been responsible for managing our Houston facilities since September 1, 2013.
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Board of Directors Changes
On February 18, 2014, we announced that Carlin G. Conner, director and Chairman of the Board of our general partner notified us of his intention to resign. Mr. Conner’s resignation was given in connection with his notice to Oiltanking GmbH and its parent company, Marquard & Bahls A.G., of his intention to resign as Managing Director of Oiltanking GmbH and Executive Board member of Marquard & Bahls. We expect that Mr. Conner will continue in his current roles until a successor is appointed. Mr. Conner is resigning to relocate back to the United States from Hamburg, Germany, and his resignation is not related to any disagreement with our directors or management or regarding any matter relating to our operations, policies or practices.
Separately, Randall J. Larson resigned as a member of the board of directors of our general partner on February 19, 2014. Prior to his resignation, Mr. Larson served as the Chairman of the Audit Committee and as a member of the Conflicts Committee of our general partner. Mr. Larson’s departure is not related to any disagreement with our directors or management or regarding any matter relating to our operations, policies or practices. Thomas M. Hart III was appointed to fill the vacancy on the board of directors created by Mr. Larson’s departure and D. Mark Leland was appointed to serve as the Chairman of the Audit Committee, in each case effective as of February 19, 2014.
Assets and Areas of Operations
Our terminal assets are strategically located along the United States Gulf Coast on the Houston Ship Channel and in Beaumont, Texas. Our facilities provide customers interconnectivity to major ports, refineries, trading hubs and end users. Certain of our facilities were designed and constructed specifically for our customers’ needs. The location and reliability of our assets, combined with our operating expertise, make us an important part of many of our customers’ supply chains.
Refiners and chemical companies typically use our terminals because their facilities may not have adequate storage capacity and sufficient dock infrastructure or do not meet specialized handling requirements for a particular product. We also provide storage services to producers, marketers and traders that require access to large amounts of strategically located storage capacity. Our geographic location, efficient and well-maintained storage assets, deep-water access and extensive distribution interconnectivity give us the flexibility to meet the evolving demands of our existing customers as well as those of prospective customers seeking terminaling and storage services along the Gulf Coast.
We believe that we are well positioned to expand our existing operations in the Gulf Coast region due to the strategic location of our assets, our deep-water access and our integrated distribution network. In addition, there are significant barriers to entry for potential competitors, including the high costs of developing infrastructure and interconnects to other facilities, the length of time and risk involved in permitting and developing new projects, the limited waterfront real estate with sufficient attributes to allow for deep-water terminaling and the specialized expertise required to acquire, operate and develop storage facilities.
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Our primary assets are our facilities and related infrastructure at our Houston and Beaumont terminals. A summary of the capacity and contract profile of these assets as of December 31, 2013 is set forth below:
Location | Active Storage Capacity (shell mmbbls) | Expansion Capacity (shell mmbbls) | No. of Active Tanks | % of Active Storage Capacity under Contract | Weighted- Average Remaining Contract Term (years) (1) | Composition of Contracted Storage Capacity | Supply Modes | Delivery Modes | ||||||||||
Houston | 16.2 | 8.0 | (2) | 76 | 99.4% | 7.9 | 78% crude oil, 16% heavy petrochemical feedstocks, 4% refined petroleum products, 2% fuel oil | Vessel, Barge, Pipeline, Railcars, Tank Trucks | Vessel, Barge, Pipeline, Railcars, Tank Trucks | |||||||||
Beaumont | 5.5 | 5.1 | (3) | 66 | 98.2% | 3.9 | 99% refined petroleum products, 1% fuel oil | Vessel, Barge, Pipeline | Vessel, Barge, Pipeline | |||||||||
Total | 21.7 | 13.1 | 142 | 98.8% | 7.1 | |||||||||||||
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(1) | Weighted-average remaining contract term is computed on the basis of revenues earned on all customer contracts for the year ended December 31, 2013. The weighted-average remaining contract term computed on the basis of revenues earned solely on storage contracts for the year ended December 31, 2013, would be 4.0 years for each of Houston, Beaumont and in total for all of our facilities. |
(2) | Includes 7.0 million barrels of announced storage capacity expansion in the permitting process and/or construction as of December 31, 2013, of which 210,000 barrels of this capacity was placed into service in January 2014. |
(3) | Represents additional storage capacity that could be constructed at our Beaumont terminal. Amount does not include more than 20.0 million barrels of additional storage capacity which we have sufficient acreage to construct on the remote side of our terminal complex with pipeline connections to our waterfront. |
Houston Facility
We operate one of the largest third-party crude oil and refined petroleum products terminaling facilities on the Houston Ship Channel. Our Houston facility includes our Houston terminal and our Appelt terminal. Our Houston facility is also the site of one of the world’s largest LPG marine export terminals.
Our Houston facility has an aggregate active storage capacity of approximately 16.2 million barrels and provides integrated terminaling services to major integrated oil companies, marketers, distributors and chemical companies. This active storage capacity does not include 7.0 million barrels of storage capacity that we are in the process of completing for customers, of which 210,000 barrels were placed into service in January 2014. Of the remaining 6.8 million barrels, 3.3 million barrels under construction (Appelt II) are expected to be placed into service in the third and fourth quarters of 2014, 400,000 barrels are expected to be placed into service by the end of 2014, and 3.1 million barrels to be constructed (Appelt III) are expected to be placed into service during the fourth quarter of 2015 and first quarter of 2016.
The principal products handled at our Houston facility are crude oil, the inputs for chemical production (such as naphtha and condensate), which are referred to as chemical feedstocks, LPG and refined petroleum products, such as gasoline and distillates. Crude oil accounts for approximately 78% of our active storage capacity.
Our storage and distribution network is highly integrated with the greater Houston petrochemical and refining complex. The facility handles products through a number of transportation modes, including proprietary pipelines or pipelines interconnected to local refineries and production facilities, including Houston Refining LP’s refinery in
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Houston, Texas, Pasadena Refining System Inc.’s refinery in Pasadena, Texas, ExxonMobil Corporation’s refinery in Baytown, Texas, Marathon Petroleum Corporation’s refinery in Texas City, Texas, Valero Energy Corporation’s refinery in Houston, Texas, and Shell Deer Park Refining Company’s refinery in Deer Park, Texas. The pipeline expansion projects discussed above would further expand our extensive pipeline network and distribution capabilities.
We believe our Houston facility is well positioned to take advantage of changing crude oil logistics in the Gulf Coast as a result of announced pipeline construction projects and waterborne and rail movements that, in the aggregate, could transport as much as four million barrels of oil per day into and throughout the Gulf Coast region if completed as planned over the next few years. To capitalize on these expected new sources of crude oil supply, during 2012, we purchased approximately 122 acres of land, which we refer to as our Appelt property, and various rights-of-way necessary to construct additional crude storage capacity on property to be connected to our Houston facility and to expand our connectivity to other storage and transportation hubs in the Houston market. Since 2012, we have announced expansion projects at our Appelt property totaling approximately 10.0 million barrels of storage capacity, of which approximately 3.2 million barrels has been placed into service.
At December 31, 2013, we had firm contracts for approximately 99.4% of our 16.2 million barrels of storage capacity at our Houston facility. The weighted-average remaining contract term for our Houston facility contracts is approximately 7.9 years.
Our Houston facility has extensive waterfront access, consisting of six deep-water ship docks and two barge docks. We can accommodate vessels with up to a 45 foot draft, including Suezmax tankers, which are the largest tankers that can navigate the Houston Ship Channel. We believe that our location on the Houston Ship Channel to the east of the Beltway 8 Bridge enables us to handle larger vessels than our competitors who are located to the west of the Beltway 8 Bridge because our waterfront has fewer draft and beam restrictions.
The size and structure of our waterfront at the Houston facility allows us not only to receive and unload products for our storage customers, but also to receive throughput fees from customers for the use of our docks. We provide vessel-based LPG terminaling services to Enterprise, which has constructed its LPG marine export terminal at our Houston terminal. Enterprise has announced its intention to expand this facility’s capacity of 7.5 million barrels per month of low-ethane propane and/or butane to more than 16 million barrels per month by the end of 2015.
Our real property at our Houston facility consists of approximately 386 acres, all of which we own in fee. In addition, we own approximately 24 acres at the Crossroads Interchange approximately six miles from our Houston facility.
Beaumont Terminal
Our Beaumont terminal, located on the Neches River, serves as a regional strategic and trading hub for refined petroleum products for refineries located in the Gulf Coast region. Our facility has an aggregate active storage capacity of approximately 5.5 million barrels and provides integrated terminaling services to major integrated oil companies, distributors, marketers and chemical and petrochemical companies. The principal products handled at our Beaumont terminal complex are refined petroleum products, which accounted for approximately 99% of our active storage utilization as of December 31, 2013.
Our storage and distribution network is highly integrated with the Beaumont/Port Arthur petrochemical and refining complex, and provides our customers with additional services, such as mixing, blending, heating and marine vapor recovery. Our Beaumont facility handles products through a number of transportation modes, including third-party pipelines interconnected to local refineries and production facilities, our dedicated pipeline system to Huntsman’s chemical production facility in Port Neches, and third-party crude and refined petroleum products tankers and barges arriving at our deep-water docks.
Our waterfront capabilities currently consist of two deep-water ship docks that can accommodate vessels with drafts of up to 40 feet, and two barge docks that can accommodate vessels with drafts of up to 12 feet. We also own
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waterfront acreage adjacent to our terminal sufficient to accommodate two additional deep-water docks. The additional waterfront acreage, if developed, would approximately double our current deep-water dock capacity.
At December 31, 2013, we had firm contracts for approximately 98.2% of our 5.5 million barrels of storage capacity at our Beaumont terminal. The weighted-average remaining contract term for our Beaumont terminal contracts is approximately 3.9 years.
Our real property at our Beaumont terminal consists of 1,339 acres, all of which we own in fee. We own acreage adjacent to our waterfront on which we can construct tanks with an additional 5.1 million barrels of storage capacity. Additionally, we could construct more than 20.0 million barrels of additional storage capacity on the remote side of our terminal complex with pipeline connections to our waterfront. We believe that we have the existing acreage and potential for connectivity with major pipelines to rapidly and efficiently expand our Beaumont terminal if increasing crude oil supplies or other changing market trends create favorable conditions for growth.
Our Operations
We provide integrated terminaling, storage, pipeline and related services for third-party companies engaged in the production, distribution and marketing of crude oil, refined petroleum products and LPG. We generate our revenues exclusively through the provision of services to our customers. We do not take ownership of the crude oil, refined products or LPG that we terminal, store or transport nor do we engage in any marketing or trading of commodities. The types of fees we charge are:
• | Storage Services Fees. For the year ended December 31, 2013, we generated approximately 57% of our revenues from fixed monthly fees for storage services, which our customers pay to reserve storage space in our tanks and for our commitment to receive an agreed volume of product volume, or throughput, on their behalf. These fees are owed to us regardless of the actual storage capacity utilized by our customers or the amount of product throughput. |
• | Throughput Fees. For the year ended December 31, 2013, we generated approximately 38% of our revenues from throughput fees. Our non-storage customers pay us throughput fees to receive or deliver volumes of products on their behalf to designated pipelines, third-party storage facilities or waterborne vessels or barges. In addition, our storage customers pay us throughput fees when we handle product volumes in excess of agreed volumes negotiated in connection with storage services. Throughput fees are also earned in connection with the volume of products loaded or unloaded across our docks, and may be in the form of a fixed throughput fee rate or based upon the margins earned by the customer. The revenues we generate from throughput fees vary based upon the volumes of products received at or delivered from our terminals and, with respect to some throughput services, the margins realized by our customers. |
• | Ancillary Services Fees. For the year ended December 31, 2013, we generated approximately 5% of our revenues from fees associated with ancillary services, such as heating, mixing and blending products stored in our tanks, transferring products between tanks, marine vapor recovery and other miscellaneous income. The revenues we generate from ancillary services fees vary based upon the activity levels of our customers. |
Customers and Competition
Customers
We provide storage and terminaling services to major integrated oil companies, refiners, marketers, distributors and chemical and petrochemical companies. We typically enter into long-term customer contracts that include minimum volume commitments and inflation escalators. Our customers generally have strong credit profiles and most of our customers have investment grade credit ratings.
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Because we are an independent terminal operator, we have a diversified customer base. As of December 31, 2013, our Houston facility had terminal services agreements with 16 customers and our Beaumont terminal had terminal services agreements with 14 customers. The following table presents percentages of revenues associated with our significant customers for the periods indicated:
Year Ended December 31, | |||||
2013 | 2012 | 2011 | |||
Enterprise Products Partners L.P. | 29% | 13% | 12% | ||
ExxonMobil Corporation | 9% | 11% | 12% | ||
LyondellBasell Industries, N.V. | 9% | 12% | 13% | ||
BP p.l.c. | 8% | 16% | 15% | ||
Royal Dutch Shell plc | 7% | 9% | 11% | ||
Total percentage of revenues associated with significant customers | 62% | 61% | 63% | ||
No other customer accounted for more than 10% of our revenues during the years ended December 31, 2013, 2012 and 2011.
Competition
Independent terminal operators generally compete on the basis of the location and versatility of facilities, service and price. A favorably located terminal will have access to various cost-effective transportation modes, both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the operator.
We face significant competition from a variety of international, national and regional energy companies, including large, diversified midstream partnerships, global terminal operators and large multi-national energy companies of varying sizes, financial resources and experience. We believe that we are favorably positioned to compete in the industry due to the strategic location of our terminals in the Gulf Coast, their integration with area refineries, our reputation, our efficiency in docking vessels on our waterfront, the prices we charge for our services and the connectivity, quality and versatility of our services.
The competitiveness of our service offerings could be significantly impacted by the entry of new competitors into the markets served by our Houston and Beaumont facilities. We believe, however, that significant barriers to entry exist in the crude oil and refined products terminaling and storage business, particularly for marine terminals and distribution assets. These barriers include significant costs and execution risk, a lengthy permitting and development cycle, financing challenges, shortage of personnel with the requisite expertise and the finite number of sites suitable for development.
Seasonality
The crude oil, refined petroleum products and LPG throughput in our terminals is directly affected by the level of supply and demand for crude oil, refined petroleum products and LPG in the markets served directly or indirectly by our assets, which can fluctuate seasonally, particularly due to seasonal shutdowns of refineries during the spring months. Because a significant percentage of our cash flow is derived from fixed storage services fees under multi-year contracts, our revenues are generally not substantially seasonal in nature, nor are they typically affected by weather and price volatility.
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Employees
We are managed and operated by the officers of our general partner and do not have any direct employees. All of the employees that conduct our business pursuant to the Services Agreement are employed by a wholly owned subsidiary of OTA. As of December 31, 2013, OTA had approximately 220 employees providing services to us.
We compensate OTA for providing those employee services pursuant to the Services Agreement. None of OTA’s employees are a party to collective bargaining agreements, and we have never experienced any work stoppages or other significant labor problems.
Capital Expenditures
We make capital expenditures in order to maintain and enhance the safety and integrity of our terminals, pipelines, storage facilities and related assets, to expand the reach or capacity of those assets, to improve the efficiency of our operations and to pursue new business opportunities. Maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity. Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity over the long term. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
During 2013, we spent approximately $180.7 million for capital expenditures, of which $3.1 million related to maintenance capital projects and $177.6 million related to expansion projects. During 2013, we continued construction of new storage capacity at our Houston area terminals and associated crude oil pipeline infrastructure investments.
During 2014, we expect to spend approximately $230.0 million to $250.0 million for capital expenditures, of which approximately $8.5 million is expected to relate to maintenance capital expenditures and approximately $10.0 million to $15.0 million is expected to relate to upgrades and improvements to our existing infrastructure to increase throughput capacity and increase our ability to provide fee-based services, such as heating and blending. A majority of the expansion capital expenditures projected for 2014 of approximately $190.7 million relates to storage capacity projects at our Houston area terminals (Appelt II and Appelt III), the LPG dock expansion project and the pipeline expansion projects.
Environmental and Occupational Safety and Health Matters
General
Our operations are subject to stringent federal, state and local laws and regulations governing the release of materials into the environment, health and safety aspects of our operations, and otherwise relating to the protection of the environment. Compliance with these laws and regulations may require the acquisition of permits to conduct regulated activities; restrict the type, quantities and concentration of wastes or other pollutants that may be emitted, discharged or disposed into or onto to the land, air and water; apply specific health and safety criteria addressing worker protection; and impose liabilities for pollution from operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may limit or prohibit some or all of our operations. As with the industry generally, compliance with existing and anticipated arising environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, operate and upgrade equipment and facilities. We believe our facilities are in substantial compliance with applicable environmental laws and regulations, but these requirements are subject to frequent change by regulatory authorities, and continued or future compliance with such laws and regulations may require us to incur significant expenditures.
The following is a discussion of the significant environmental and occupational safety and health laws and regulations affecting our operations.
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Hazardous Substances and Wastes
The federal Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), also known as Superfund, and comparable state laws impose liability, without regard to fault or to the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we generate waste that falls within CERCLA’s definition of a “hazardous substance.”
We also generate hazardous and non-hazardous solid wastes, which are subject to the requirements of the federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA requirements relating to hazardous wastes because our operations generate minimal quantities of hazardous wastes. However, much of our generated wastes remain subject to non-hazardous solid waste requirements and it is possible that some wastes generated by us that are currently classified as non-hazardous may in the future be designated as hazardous wastes, resulting in those wastes becoming subject to more rigorous and costly storage, treatment, transportation and disposal requirements than are non-hazardous wastes.
We currently own and lease properties where hydrocarbon products and other materials are being or have been handled for many years. Although we have utilized operating and waste management practices that have always been the then-current commonly accepted industry standards, certain materials may have been spilled or released on or under properties that we owned or leased. In addition, certain materials were removed from our locations and taken to properties owned and operated by third parties not under our control, for disposal, recycling, and/or reclaiming. Any materials that have been spilled or released to the environment, or removed for disposal, recycling, and/or reclamation, may be subject to CERCLA, RCRA, and other federal laws and requirements under applicable state laws. Under these federal and state laws, we could be required to perform a variety of remedial actions, including those related to elevated contaminant levels found in soil, groundwater, and/or surface water to the extent we are not indemnified for such matters.
Air Emissions
Our operations are subject to the federal Clean Air Act, as amended, and comparable state and local statutes. These laws and regulations govern emissions of air pollutants from various industrial sources and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to result in the emission of new air pollutants or increased existing air pollutants, obtain and comply with air permits containing various emissions and operational limitations, and use specific emission control technologies to limit emissions of pollutants. Although we may be required to incur certain capital expenditures in the future in connection with obtaining and maintaining operating permits and approvals for air emissions, we do not believe that our operations will be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.
Climate Change
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the federal Clean Air Act including requirements that may trigger construction and operating permit review for GHG
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emissions from certain large stationary sources. We may be required to install “best available control technology” to limit future emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they emit large volumes of GHGs, but we do not expect that they will have a material adverse effect on the cost of our operations. The EPA has also adopted rules requiring the annual monitoring and reporting of GHG emissions from certain sources in the United States, including, among others, onshore oil and natural gas production, processing, transmission, storage and distribution facilities. In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, and a number of states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs. Moreover, if Congress undertakes comprehensive tax reform, it is possible that such reform may include a carbon tax. The adoption of any legislation or regulations that requires reporting of GHGs, imposes a carbon tax, or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for oil and natural gas that is produced, which could decrease demand for our storage services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.
Water
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Any unpermitted discharge of pollutants could result in substantial liabilities, including penalties and significant remedial obligations. Our operations are adjacent to waterways. The transportation of crude oil and refined products over water involves risk and subjects us to the provisions of the Oil Pollution Act, as amended, and related state requirements, which subject owners of covered facilities to strict, joint, and potentially unlimited liability for removal costs and other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States. Spill prevention control and countermeasure requirements under applicable laws and regulations mandate containment to mitigate or prevent contamination of navigable waters in the event of an oil overflow, rupture or leak. For example, the Clean Water Act requires us to maintain spill prevention control and countermeasure plans at our facilities. In addition, these legal requirements direct most oil transport and storage companies to maintain various oil spill prevention and oil spill contingency plans. We maintain such plans, and where required have submitted amended plans and received federal and state approvals necessary to substantially comply with these applicable requirements. We have trained employees at our Houston and Beaumont facilities who serve as company emergency responders and also contract with various spill-response specialists to ensure appropriate expertise and spill-response resources are available for any contingency, including spills of oil or refined products, from our facilities.
Response equipment maintained at each facility is inventoried in the Facility Response Plan found at each facility. This equipment is handled by employees trained as company emergency responders at each of our facilities. These employees receive annual refresher emergency responder training as well as annual and other periodic drills and training to ensure that they are able to mitigate spills or other releases, and control site response activities, either on their own or, if necessary, until various third-party spill-response specialists whom we engage are able to respond.
Supporting our company emergency responders, as necessary, are various third-party spill-response specialists with whom we contract so that we may ensure appropriate expertise is available for any contingency at our facilities, including spills of oil or refined products. Our primary third-party spill-response specialist is Garner Environmental Services, Inc., which has extensive experience in the clean-up of hydrocarbons resulting from spills, blow-outs and natural disasters and is fully certified as an Oil Spill Removal Organization by the U.S. Coast Guard. Garner has offices near our facilities and maintains a large inventory of emergency response equipment near our facilities. Garner’s emergency response capabilities are bolstered by arrangements that it has entered into with other emergency response entities to provide additional trained responders in the event of multiple spills or other situations where a large deployment of emergency responders is necessary. We also maintain relationships and service agreements with multiple other emergency response providers.
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Endangered Species Act
The Endangered Species Act restricts activities that may affect endangered species or their habitats. We believe that we are in compliance with the Endangered Species Act. However, the discovery of previously unidentified endangered species in areas where we operate could cause us to incur additional costs or become subject to operating restrictions or bans in the affected area.
Hazardous Materials Transportation Requirements
Our crude oil, refined petroleum product and LPG pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation, under the Hazardous Liquids Pipeline Safety Act of 1979, as amended, and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, through amendment of the HLPSA by the Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for hazardous liquids and gas transportation pipelines that, in the event of a pipeline leak or rupture, could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. Moreover, the PHMSA has adopted regulations requiring operators to maintain comprehensive spill response plans, including extensive spill response training for pipeline personnel. We believe our operations are in substantial compliance with these laws and regulations.
Most recently, the hazardous liquid and gas transportation pipeline safety laws were amended on January 3, 2012, when President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), which act requires increased safety measures for hazardous liquids and gas transportation pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines is above 30% of specified minimum yield strength, and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmission pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1.0 million to $2.0 million for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of PHMSA guidance with respect thereto could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial position.
Occupational Safety and Health
We are subject to the requirements of the Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with applicable OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
Title to Properties and Rights-of-Way
Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities,
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permitting the use of such land for our operations. A portion of the land on which our pipelines and facilities are located is owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our pipelines and facilities are located is held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We believe that we have satisfactory leasehold estates or fee ownership to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.
Safety and Maintenance
We perform preventive and normal maintenance on all of our storage tanks, terminals and pipeline systems and make repairs and replacements when necessary or appropriate. We also conduct routine and required inspections of those assets in accordance with applicable regulations. At our terminals, the tanks designed for storage of products with a vapor pressure of 0.5 pound-force per square inch absolute, or greater, are equipped with Internal Floating Roofs to minimize regulated emissions and prevent potentially flammable vapor accumulation.
Our terminal facilities have response plans, spill prevention and control plans, and other programs in place to respond to emergencies. Our truck and rail loading racks are protected with firefighting systems. We continually strive to maintain compliance with applicable air, solid waste and wastewater regulations.
On our pipelines, we use external coatings and impressed current cathodic protection systems to protect against external corrosion. We conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards. We continually monitor, test and record the effectiveness of these corrosion inhibiting systems. We also monitor the structural integrity of selected segments of our pipelines through a program of periodic internal assessments using high resolution internal inspection tools, as well as hydrostatic testing that conforms to federal standards. We accompany these assessments with a review of the data and mitigate or repair anomalies, as required, to ensure the integrity of our pipelines. We have initiated a risk-based approach to prioritizing the pipeline segments for future integrity assessments to ensure that the highest risk segments receive the highest priority for scheduling internal inspections or pressure tests for integrity.
Insurance
Our operations and assets are insured under a global insurance program administered by Oiltanking GmbH and placed with Lloyd’s of London and other international insurers. The major elements of this program include property damage (including terrorism), business interruption, third-party liability and environmental impairment insurance. We are invoiced directly by the brokers for this coverage. To the extent that other companies in this program experience covered losses, the limit of our coverage for potential losses may be decreased. In addition to the Oiltanking GmbH insurance program, OTA has a separate commercial liability policy including automobile, boiler and machinery, commercial crime, executive risk and property coverage. We also have director and officer liability insurance for the directors and officers of our general partner.
Our insurance does not cover every potential risk associated with operating our storage facilities, pipeline systems and related facilities, including the potential loss of significant revenues. We believe we are adequately insured for liability and property damage to others with respect to our operations. With respect to all of our coverage, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.
Available Information
We file annual, quarterly and current reports and other documents with the SEC under the Securities Exchange Act of 1934 (the “Exchange Act”). You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operations of the Public Reference Room by calling the SEC at (800) SEC-0330. In addition, the SEC maintains an Internet website at www.sec.gov that contains reports and other information regarding issuers that file electronically with the SEC.
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We also make available free of charge our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, simultaneously with or as soon as reasonably practicable after filing such materials with, or furnishing such materials to, the SEC, and on or through our Internet website, www.oiltankingpartners.com. The information on our website, or information about us on any other website, is not incorporated by reference into this Report.
Disclosure Under Section 13(r) of the Exchange Act
Under Section 13(r) of the Securities Exchange Act of 1934, as amended by the Iran Threat Reduction and Syria Human Rights Act of 2012, issuers are required to include certain disclosures in their periodic reports if they or any of their “affiliates” (as defined in Rule 12b-2 thereunder) have knowingly engaged in certain specified activities relating to Iran. Disclosure is required even where the activities are conducted outside the United States by non-U.S. affiliates in compliance with applicable law, and even if the activities are not covered or prohibited by U.S. law.
Oiltanking GmbH, the ultimate parent company of our general partner, maintains a joint venture interest in Oiltanking Odfjell GmbH, which in turn owns a joint venture interest in the Exir Chemical Terminal (“ECT”) in Iran. This interest results from an investment dating back to 2002. Oiltanking GmbH currently has the contractual right to vote for the appointment of one member of ECT’s three-member board. Oiltanking GmbH provides no goods, services, technology, information or support to ECT and plays no role in the management or day-to-day operations of ECT.
Among other activities, ECT transfers naptha originating in Iraq to Oman for a customer in the United Arab Emirates. ECT does not import or handle any Iranian-origin products that are regulated under U.S., European Union or United Nations sanctions laws. ECT pays routine and standard charges (i) to the Petrochemical Special Economic Zone Organization (“Petzone”) for the use of pipelines and (ii) to Terminals and Tanks Petrochemical Co. (“TTPC”), which operates the berth. Petzone and TTPC are subsidiaries of the National Petrochemical Company, which is owned and controlled by the Government of Iran. As Oiltanking GmbH has no direct involvement in the day-to-day operations of ECT, we have no information regarding ECT’s intent to continue or not continue making the payments described above.
Oiltanking GmbH maintains an internal compliance program to ensure compliance with all applicable sanctions regimes, including sanctions laws maintained by the United States, European Union and United Nations. Although the existence of the routine payments described above may be reportable under Section 13(r), Oiltanking GmbH has informed us that neither it, nor any of its subsidiaries or affiliates, has engaged in any conduct that would be sanctionable under any of these legal regimes.
Item 1A. Risk Factors
There are many factors that may affect our business, financial condition and results of operations and investments in us. Security holders and potential investors in our securities should carefully consider the risk factors set forth below, as well as the discussion of other factors that could affect us or investments in us included elsewhere in this Report. If one or more of these risks were to materialize, our business, financial condition or results of operations could be materially and adversely affected. These known material risks could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.
Risks Inherent in Our Business
We may not have sufficient cash from operations following the establishment of cash reserves and payment of costs and expenses, including cost reimbursements to our general partner, to enable us to continue to pay distributions to our unitholders at the current rate or the minimum quarterly distribution.
We may not have sufficient cash each quarter to continue to pay distributions at the current rate or the minimum quarterly distribution. The amount of cash we can distribute on our common and subordinated units principally depends
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upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:
• | the volumes of crude oil, refined petroleum products and LPG we handle; |
• | the storage, throughput and ancillary fees (including margin sharing) with respect to volumes that we handle; |
• | damage to pipelines, facilities, related equipment and surrounding properties caused by hurricanes, earthquakes, floods, fires, severe weather, explosions and other natural disasters or acts of terrorism; |
• | inadvertent damage to pipelines from construction or damage to docks from collision with vessels; |
• | leaks or other accidental releases of products or other materials into the environment, whether as a result of human error or otherwise; |
• | planned or unplanned shutdowns of the refineries and chemical production facilities owned by our customers; |
• | prevailing economic and market conditions; |
• | difficulties in collecting our receivables because of credit or financial problems of our customers; |
• | the effects of new or expanded environmental and occupational health and safety regulations; |
• | compliance with governmental regulations, including changes in governmental regulation of the industries in which we operate; |
• | changes in tax laws; |
• | weather conditions; and |
• | force majeure events. |
In addition, the actual amount of cash we will have available for distribution depends on other factors, some of which are beyond our control, including:
• | the level of capital expenditures we make; |
• | the cost of acquisitions; |
• | our debt service requirements and other liabilities; |
• | fluctuations in our working capital needs; |
• | our ability to borrow funds and access capital markets; |
• | restrictions contained in debt agreements to which we are a party; and |
• | the amount of cash reserves established by our general partner. |
Our business would be adversely affected if the operations of our customers experienced significant interruptions. In certain circumstances, the obligations of many of our key customers under their terminal services agreements may be reduced or suspended, which would adversely affect our financial condition and results of operations.
We are dependent upon the uninterrupted operations of certain facilities owned or operated by our customers, such as the refineries and chemical production facilities we serve. Any significant interruption at these facilities or inability to transport products to or from these facilities or to or from our customers for any reason would adversely affect our results of operations, cash flow and ability to make distributions to our unitholders. Operations at our facilities and at the facilities owned or operated by our suppliers and customers could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control, such as:
• | failure to acquire or maintain necessary governmental permits or other approvals; |
• | catastrophic events, including fires, explosive incidents and hurricanes; |
• | environmental remediation; |
• | labor difficulties; |
• | disruptions in the supply of products to or from our facilities; and |
• | terrorist attacks and acts of sabotage targeting oil and gas production facilities, refineries, processing plants, terminals and other infrastructure facilities. |
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Our terminal services agreements with many of our key customers provide that, if any of a number of events occur, including certain of those events described above, which we refer to as events of force majeure, and the event significantly delays or renders performance impossible with respect to a facility, usually for a specified minimum period of days, our customers’ obligations would be temporarily suspended with respect to that facility. In that case, a significant customer’s fixed storage services fees may be reduced or suspended, even if we are contractually restricted from recontracting out the storage space in question during such force majeure period, or the contract may be subject to termination. There can be no assurance that we are adequately insured against such risks. As a result, our revenue and results of operations could be materially adversely affected.
Our financial results depend on the demand for the crude oil, refined petroleum products and LPG that we transport, store and distribute, among other factors.
Any sustained decrease in demand for crude oil, refined petroleum products and LPG in the markets served by our terminals could result in a significant reduction in storage or throughput levels at our terminals, which would reduce our cash flow and our ability to make distributions to our unitholders. Our financial results may also be affected by uncertain or changing economic conditions within certain regions. If economic and market conditions are uncertain or adverse conditions occur, we may experience material impacts on our business, financial condition and results of operations.
Other factors that could lead to a decrease in market demand include:
• | the impact of weather on demand for oil; |
• | the level of domestic oil and gas production, both on a stand-alone basis and as compared to the level of foreign oil and gas production; |
• | higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline; |
• | an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers; |
• | the increased use of alternative fuel sources, such as ethanol, biodiesel, solar and fuel cells and the increased use of electric and battery-powered engines; and |
• | an increase in the market price of crude oil that leads to higher refined petroleum product prices, which may reduce demand for refined petroleum products and drive demand for alternative products. Market prices for crude oil and refined petroleum products are subject to wide fluctuation in response to changes in global and regional supply that are beyond our control, and increases in the price of crude oil may result in a lower demand for refined petroleum products. |
Any decrease in supply and marketing activities may result in reduced throughput volumes at our terminals, which would adversely affect our financial condition and results of operations.
A decrease in the volume of LPG transported across our docks, or a decrease in the margin our LPG customer receives subject to our margin sharing arrangement, could negatively impact the throughput revenues we earn.
In March 2013, we announced the expansion of our relationship with Enterprise and the construction of an additional dock to increase our ability to handle imports and exports of LPG and other products at our facility on the Houston Ship Channel. Pursuant to this arrangement, we participate in margin sharing with Enterprise on vessels loaded at our Houston facility. Initially, we only participated in margin sharing on specified vessels, but beginning in January 2014, we began participating in margin sharing on all customer vessels loaded at our Houston facility under the arrangement. In January 2014, we announced a further expansion of our terminal service agreement with Enterprise, which, among other things, increased the dock capacity we made available to Enterprise and extended the term of the agreement to 50 years.
During the year ended December 31, 2013, our throughput revenues increased 173.8% as compared to the prior year. A significant proportion of the increase was attributable to amounts we received under the LPG margin sharing arrangement. We do not have direct commodity exposure under the margin sharing arrangement, but throughput revenue
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we receive on qualifying vessels under this arrangement is determined based on: (i) the volumes of LPG transported across our docks and (ii) the margin Enterprise receives on those volumes.
The number and types of vessels scheduled for loading at our facility, along with pricing to be received for LPG delivery, are determined exclusively by Enterprise and are beyond our control. In addition, during the term of the agreement, we agreed to an exclusivity provision for vessel-based LPG import and export services encompassing all of the U.S. Gulf Coast, resulting in a concentration of our LPG import and export business with a single customer. If Enterprise decreases the volume of scheduled LPG exports at our Houston facility or the margin it receives declines, our throughput revenues received under the arrangement would be lower. Moreover, if global LPG supply and demand economics shift or if other LPG import and export facilities are constructed that compete with our facility, the volume of imports loaded at our Houston facility and the margin received by Enterprise on LPG exports at our Houston facility could decline. These factors could lead to lower realized throughput revenues than we have received in prior periods.
Revenues we generate from throughput fees vary based upon the volumes of products handled at our terminals and the activity levels of our customers. Any short- or long-term decrease in the demand for the crude oil, refined petroleum products or LPG we handle or any interruptions to the operations of certain of our customers, could reduce the amount of cash we generate and adversely affect our ability to make distributions to our unitholders.
For the year ended December 31, 2013, we generated approximately 38% of our revenues from throughput fees, which our non-storage customers pay us to receive or deliver volumes of products on their behalf to designated pipelines, third-party storage facilities or waterborne transportation and our storage customers pay us to receive volumes of products on their behalf exceeding the throughput contemplated by their storage agreement with us. Throughput fees are also earned in connection with the volume of products loaded or unloaded across our docks, and may be in the form of a fixed throughput fee rate or based upon the margins earned by the customer. In addition, approximately 29% of our total revenues were generated from throughput fees charged to a single customer.
The revenues we generate from throughput fees vary based upon the volumes of products received at or delivered from our terminals, and our non-storage customers are not obligated to pay us throughput fees unless we move volumes of products across our pipelines or docks on their behalf. If one or more of our non-storage customers were to slow or suspend its operations, or otherwise experience a decrease in demand for our services, our revenues under our agreements with such customers would be reduced or suspended, resulting in a decrease in the revenues we generate.
Reduced volatility in energy prices or new government regulations could discourage our storage customers from holding positions in crude oil or refined petroleum products, which could adversely affect the demand for our storage services.
We have constructed and continue to construct new storage facilities in response to increased customer demand for storage. Many of our competitors have also built new storage facilities. The demand for new storage has resulted, in part, from our customers’ desire to have the ability to take advantage of profit opportunities created by volatility in the prices of crude oil and petroleum products. If the prices of crude oil and petroleum products become relatively stable, or if federal and/or state regulations are passed that discourage our customers from storing those commodities, demand for our storage services could decrease, in which case we may be unable to renew contracts for our storage services or be forced to reduce the rates we charge for our storage services, either of which would reduce the amount of cash we generate.
Some of our current terminal services agreements automatically renew on a short-term basis, and may be terminated at the end of the current renewal term upon requisite notice. If one or more of our current terminal services agreements is terminated and we are unable to secure comparable alternative arrangements, our financial condition and results of operations will be adversely affected.
Some of our terminal services agreements currently in effect are operating in the automatic renewal phase of the contract that begins upon the expiration of the primary contract term. Our terminal services agreements have primary contract terms that range from one to 50 years. Upon expiration of the primary contract term, these agreements may renew automatically for successive renewal terms that range from one to five years unless earlier terminated by either
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party upon the giving of the requisite notice, generally ranging from three to 18 months prior to the expiration of the applicable renewal term. If any one or more of our terminal services agreements is terminated and we are unable to secure comparable alternative arrangements, we may not be able to generate sufficient additional revenue from third parties to replace any shortfall in revenue or increase in costs. Additionally, we may incur substantial costs if modifications to our terminals are required by a new or renegotiated terminal services agreement. The occurrence of any one or more of these events could have a material impact on our financial condition and results of operations.
There are a number of significant expansion projects of other companies that are expected to be completed within the next few years that could impact demand for our services.
We believe that current and planned pipeline expansion projects of other companies will introduce significant new crude oil supplies to the Gulf Coast through proposed pipeline projects that, if approved and completed as expected, could transport nearly 3.5 million barrels of crude oil per day into and throughout the region by the end of 2015. These or other pipeline construction projects have resulted in pipeline-delivered crude oil accounting for a growing share of the crude oil supplies utilized by our customers, causing a decrease in waterborne foreign crude imports by our customers. As a result, our excess waterfront capacity created by this shift is increasingly being used for exports. However, to the extent we are unable to utilize excess capacity caused by decreasing imports, we may not be able to realize the full value of our waterfront assets.
In addition, a number of other companies have announced plans to construct or expand export infrastructure within the next few years to accommodate increasing exports of LPG. These additional infrastructure projects may compete with the LPG export facilities that we are in the process of expanding with Enterprise. For more information on our LPG expansion projects, see “Item 1. Business — 2013 and Recent Developments — LPG Export Terminal Agreement and Dock Expansion Project.” If the construction of LPG export infrastructure outpaces growth in LPG production and export, we may not be able to realize the full value of our LPG expansion projects.
Competition from other terminals that are able to supply our customers with comparable storage capacity at a lower price could adversely affect our financial condition and results of operations.
We face competition from other terminals that may be able to supply our customers with integrated terminaling services on a more competitive basis. We compete with national, regional and local terminal and storage companies, including major integrated oil companies, of varying sizes, financial resources and experience. Our ability to compete could be harmed by factors we cannot control, including:
• | our competitors’ construction of new assets or redeployment of existing assets in a manner that would result in more intense competition in the markets we serve; |
• | the perception that another company may provide better service; and |
• | the availability of alternative supply points or supply points located closer to our customers’ operations. |
Any combination of these factors could result in our customers utilizing the assets and services of our competitors instead of our assets and services, or us being required to lower our prices or increase our costs to retain our customers, either of which could adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions to our unitholders.
Our expansion of existing assets and construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our operations and financial condition.
A portion of our strategy to grow our business and increase distributions to unitholders is dependent on our ability to expand existing assets and to construct additional assets. The construction of a new terminal, or the expansion of an existing terminal, such as by increasing storage capacity or otherwise, involves numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control. Moreover, we may not receive sufficient long-term contractual commitments from customers to provide the revenue needed to support such projects. As a result, we may construct new facilities that are not able to attract enough storage customers or throughput to achieve our expected
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investment return, which could adversely affect our results of operations and financial condition and our ability to make distributions to our unitholders.
If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost. We may be unable to negotiate acceptable interconnection agreements with third-party pipelines to provide destinations for increased throughput. Even if we receive sufficient multi-year contractual commitments from customers to provide the revenue needed to support such projects and we complete our construction projects as planned, we may not realize an increase in revenue for an extended period of time. For instance, if we build a new terminal, the construction will occur over an extended period of time and we will not receive any material increases in revenues until after completion of the project. Any of these circumstances could adversely affect our results of operations and financial condition and our ability to make distributions to our unitholders.
If we are unable to make acquisitions on economically acceptable terms, our future growth would be limited, and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.
A portion of our strategy to grow our business and increase distributions to unitholders is dependent on our ability to make acquisitions that result in an increase in our cash available for distribution per unit. If we are unable to make acquisitions, including from OTA and its affiliates, because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, we are unable to obtain financing for these acquisitions on economically acceptable terms or we are outbid by competitors, our future growth and ability to increase distributions will be limited. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in our cash available for distribution per unit. Any acquisition involves potential risks, some of which are beyond our control, including, among other things:
• | mistaken assumptions about revenues and costs, including synergies; |
• | an inability to integrate successfully the businesses we acquire; |
• | an inability to hire, train or retain qualified personnel to manage and operate our business and newly acquired assets; |
• | the assumption of unknown liabilities; |
• | limitations on rights to indemnity from the seller; |
• | mistaken assumptions about the overall costs of equity or debt; |
• | the diversion of management’s attention from other business concerns; |
• | unforeseen difficulties operating in new product areas or new geographic areas; and |
• | customer or key employee losses at the acquired businesses. |
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
Because our assets are exclusively located in the U.S. Gulf Coast region, our ability to make distributions to our unitholders could be adversely affected.
We rely exclusively on sales generated from products distributed from the terminals we own, which are exclusively located in the Gulf Coast region. Due to our lack of diversification in asset type and location, an adverse development in these businesses or areas, including adverse developments due to catastrophic events or weather and decreases in demand for refined petroleum products, could have a significantly greater impact on our results of operations and cash available for distribution to our unitholders than if we maintained more diverse assets and locations.
We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our financial results and cash available for distribution.
We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers. Approximately 62% of our revenues for the year ended December 31, 2013 were attributable to our five largest customers. Our credit
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procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use the capacity could have a material adverse effect on our business, financial condition, results of operations and ability to pay distributions to our unitholders.
Restrictions in our debt agreements could adversely affect our business, financial condition or results of operations.
Under our loan agreements with OT Finance, we are prohibited from incurring additional indebtedness from third parties without the approval of OT Finance. In addition, these loan agreements contain covenants that require us to maintain certain debt, leverage and equity ratios and prohibit us from pledging our assets to third parties. Our revolving line of credit with OT Finance contains similar financial covenants that could restrict our ability to make cash distributions to our unitholders. As a result, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
Any reduction in the capability of our customers to utilize third-party pipelines that interconnect with our terminals, or to continue utilizing them at current costs, could cause a reduction of volumes transported through our terminals.
Many users of our terminals are dependent upon connections to third-party pipelines, to receive and deliver crude oil, refined petroleum products and LPG. Any interruptions or reduction in the capabilities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes would result in reduced volumes transported through our terminals. Similarly, if additional shippers begin transporting volume over interconnecting pipelines, the allocations to our existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported through our terminals. Allocation reductions of this nature are not infrequent and are beyond our control. In addition, if the costs to us or our storage service customers to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. Any such increases in cost, interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on our financial position, results of operations or cash flows.
Mergers among our customers and competitors could result in lower volumes being stored in or distributed through our terminals, thereby reducing the amount of cash we generate.
Mergers between our existing customers and our competitors could provide strong economic incentives for the combined entities to utilize their existing systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and we could experience difficulty in replacing those lost volumes and revenues. Because most of our operating costs are fixed, a reduction in volumes would result not only in less revenue, but also a decline in cash flow of a similar magnitude, which would adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions.
Some of our storage tanks and portions of our pipeline system have been in service for several decades.
Our pipeline and storage assets are generally long-lived assets. As a result, some of those assets have been in service for many decades. The age and condition of these assets could result in increased maintenance or remediation expenditures and an increased risk of product releases and associated costs and liabilities. Any significant increase in these expenditures, costs or liabilities could materially adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions.
Our operations are subject to operational hazards and unforeseen interruptions, including interruptions from hurricanes or floods, for which we may not be adequately insured.
Our primary operations are currently all located in the Gulf Coast region, and are subject to operational hazards and unforeseen interruptions, including interruptions from hurricanes or floods, which have historically impacted the
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region with some regularity. Each of our Houston and Beaumont terminals, for example, has experienced damage and interruption of business due to hurricanes. We may also be affected by factors such as adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures, disruptions in supply infrastructure or logistics and other events beyond our control. In addition, our operations are exposed to other potential natural disasters, including tornadoes, storms, floods and/or earthquakes. Moreover, some scientists have concluded that increasing concentrations of GHG emissions in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods. If any of these events were to occur, we could incur substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of our related operations.
We are not fully insured against all risks incident to our business. Certain of our insurance policies that are under the global insurance program administered by Oiltanking GmbH provide coverage to affiliated entities in the Oiltanking Group that we do not own. This allocation may result in limiting the amount of recovery available to us for purposes of covered losses.
Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In addition sub-limits have been imposed for certain risks. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we are not fully insured, it could have a material adverse effect on our financial condition, results of operations and cash available for distribution to unitholders.
We may incur significant costs and liabilities in complying with stringent environmental and occupational health and safety laws and regulations.
Our operations involve the transportation and storage of crude oil, refined petroleum products and LPG and are subject to federal, state, and local laws and regulations governing the release of materials into the environment, occupational health and safety aspects of our operations, and otherwise relating to the protection of the environment. Compliance with this complex array of federal, state, and local laws and regulations is difficult and may require significant capital expenditures and operating costs to mitigate or prevent pollution. Moreover, our business is subject to accidental spills, discharges or other releases of refined petroleum products or crude oil, hazardous substances or wastes into the environment and neighboring areas, in which events joint and several, strict liability may be imposed against us under certain environmental laws for costs required to remediate and restore impacted properties, for claims made by neighboring landowners and other third parties for personal injury, natural resource and property damages, and for costs required to conduct health studies. Failure to comply with applicable environmental, health, and safety laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, and permit revocations, the imposition of investigatory, corrective action, or remedial obligations and the issuance of injunctions limiting or prohibiting some or all of our operations.
New laws and regulations, amendment of existing laws and regulations, increased government enforcement or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. We are not able to predict the impact of new or changed laws or regulations or how such legal requirements are interpreted or enforced, but any such expenditures or costs for environmental and occupational health and safety compliance could have a material adverse effect on our results of operations, financial condition and profitability.
We could incur significant costs and liabilities in responding to contamination that occurs at our facilities.
There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our handling of petroleum hydrocarbons, hazardous substances and wastes, because of air emissions, water discharges and waste practices related to our operations, and as a result of historical operations and waste disposal practices of prior owners of our facilities. Our pipeline and terminal facilities have been used for transportation, storage and distribution of crude oil, refined petroleum products and LPG for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, refined petroleum products or crude oil, hydrocarbons, hazardous
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substances and wastes from time to time have been spilled or released on or under the terminal properties. In addition, the terminal properties were previously owned and operated by other parties and those parties from time to time also have spilled or released refined petroleum products or crude oil, hydrocarbons, hazardous substances or wastes. The terminal properties are subject to federal, state and local laws that impose investigatory, corrective action and remedial obligations, some of which are joint and several or strict liability obligations without regard to fault, to address and prevent environmental contamination. We may incur significant costs and liabilities in responding to any soil and groundwater contamination that occurs on our properties, even if the contamination was caused by prior owners and operators of our facilities. We may not be able to recover some or any of these costs from insurance or other sources of contractual indemnity. To the extent that the costs associated with meeting any or all of these requirements are substantial and not adequately provided for, there could be a material adverse effect on our business, financial condition and results of operations.
Climate change legislation or regulations restricting emissions of GHGs could result in increased operating and capital costs and reduced demand for our storage services.
The EPA has adopted rules for establishing a reporting program for emissions of GHGs from specified large GHG emissions sources in the United States and subsequently expanded the scope of this rule to include the reporting of GHG emissions from onshore oil and natural gas processing, transmission, storage and distribution facilities. Operators of covered sources in the United States must annually monitor and report these GHG emissions to specified governmental agencies, with operators in Texas reporting to the EPA. Certain of our facilities may become subject to the federal GHG reporting requirements because of combustion GHG emissions and potential fugitive emissions that exceed reporting thresholds. To the extent we are required to comply with this reporting program, it increases our operating costs.
Following its determination in December 2009 that emissions of GHGs present a danger to public health and the environment, the EPA promulgated regulations establishing Title V and Prevention of Significant Deterioration (“PSD”) permitting reviews for certain large stationary sources that are potential major sources of GHGs emissions. In the absence of any control requirements for GHGs for our facilities that would need to be incorporated into existing Title V permits, we believe the impact of these permitting requirements on our facilities will not be material. However, we may be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs. Best available control technology is determined on a case-by-case basis by the relevant permitting agency. Our experience has been that PSD permits with GHG emissions limitations have generally required efficient combustion requirements on sources that burn large volumes of fossil fuels rather than post-combustion GHG capture requirements. Consequently, to the extent that the EPA imposes efficient combustion requirements, we do not anticipate that they will have a material adverse effect on the cost of our operations.
While the federal Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the U.S., a number of states, excluding Texas, and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions. Two of the more significant non-federal GHG programs are the Regional Greenhouse Gas Initiative (“RGGI”) located in the Northeast United States, and California’s cap-and-trade program. We currently do not conduct operations in California or the areas covered by RGGI. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations and cash flows.
Finally, should Congress undertake comprehensive tax reform, it is possible that such reform will include a carbon tax. A carbon tax could impose additional direct costs on our operations and reduce demand for refined products. The ultimate impact of any carbon tax on our operations would further depend upon whether a carbon tax supplanted the other federal GHG regulations to which we are currently subject or is administered as an additional program.
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Terrorist attacks or other security threats aimed at our facilities or surrounding areas could adversely affect our business.
The U.S. government has issued warnings that energy assets, specifically the nation’s pipeline and terminal infrastructure, may be the future targets of terrorist organizations. In addition to the threat of terrorist attacks, we face various other security threats, including cyber-security threats to gain unauthorized access to sensitive information or to render data or systems unusable. Cyber-security attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Any terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, refineries or terminals could materially and adversely affect our financial condition, results of operations or cash flows.
We rely upon certain critical information systems for the operation of our business, and the failure of any critical information system may result in harm to our business.
We are heavily dependent on our technology infrastructure and maintain and rely upon certain critical information systems for the effective operation of our business. These information systems include data network and telecommunications, internet access and our websites, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our pipelines and terminals. These information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. To the extent that these information systems are under our control, we have implemented measures, such as virus protection software, intrusion detection systems and emergency recovery processes to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe. Any compromise of our data security or our inability to use or access these information systems at critical points in time could unfavorably impact the timely and efficient operation of our business and subject us to additional costs and liabilities, which could adversely affect our results of operations. Finally, federal legislation relating to cyber-security threats may be enacted that could impose additional requirements on our operations.
Risks Relating to Our Structure
OTA owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including OTA, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.
OTA owns and controls our general partner and appoints all of the directors of our general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to OTA. Therefore, conflicts of interest may arise between OTA and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:
• | our general partner is allowed to take into account the interests of parties other than us, such as OTA, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders; |
• | neither our partnership agreement nor any other agreement requires OTA to pursue a business strategy that favors us; |
• | our partnership agreement limits the liability of and reduces fiduciary duties owed by our general partner and also restricts the remedies available to unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty; |
• | except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; |
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• | our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders; |
• | our general partner determines the amount and timing of any capital expenditure and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. Our partnership agreement does not set a limit on the amount of maintenance capital expenditures that our general partner may incur. This determination can affect the amount of cash that is distributed to our unitholders which, in turn, may affect the ability of the subordinated units to convert; |
• | our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period; |
• | our partnership agreement permits us to distribute up to $30.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the IDRs; |
• | our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf; |
• | our general partner intends to limit its liability regarding our contractual and other obligations; |
• | our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units; |
• | our general partner controls the enforcement of obligations that it and its affiliates owe to us; |
• | our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and |
• | our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s IDRs without the approval of the conflicts committee of the board of directors of our general partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations. |
In addition, we may compete directly with entities in which OTA has an interest for acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
We expect that we will distribute all of our available cash (as defined in our partnership agreement) to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings, borrowings from OT Finance and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
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In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or in our revolving line of credit on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.
Our general partner’s board of directors’ absolute discretion in determining our level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.
Our partnership agreement requires our general partner’s board of directors to deduct from available cash the amount of any cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner’s board of directors to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. Any such cash reserves will reduce the amount of cash currently available for distribution to our unitholders.
The amount of estimated maintenance capital expenditures our general partner is required to deduct from operating surplus each quarter could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuating maintenance capital expenditures. Our annual estimated maintenance capital expenditures for purposes of calculating operating surplus is approximately $8.5 million for 2014. This amount is based on our current estimates of the amounts of expenditures we will be required to make in the future to maintain our long-term operating capacity, which we believe to be reasonable. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. The amount of our estimated maintenance capital expenditures may be more than our actual maintenance capital expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to our unitholders. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, with any change approved by the conflicts committee. In addition to estimated maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to our unitholders.
Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.
Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
• | how to allocate business opportunities among us and its affiliates; |
• | whether to exercise its limited call right; |
• | how to exercise its voting rights with respect to the units it owns; |
• | whether to exercise its registration rights; |
• | whether to elect to reset target distribution levels; and |
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• | whether to consent to any merger or consolidation of the partnership or any amendment to the partnership agreement. |
By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.
Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
• | whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity; |
• | our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning that it believed that the decision was in the best interests of our partnership; |
• | our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and |
• | our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is: |
(1) | approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; |
(2) | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates; |
(3) | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
(4) | fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (3) and (4) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
OTA and other affiliates of our general partner may compete with us.
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. Affiliates of our general partner, including OTA and the Oiltanking Group, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. The Oiltanking Group and OTA currently hold substantial interests in other companies in the terminaling business. OTA and the Oiltanking Group make investments and purchase entities that acquire, own and operate terminaling businesses. These investments and
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acquisitions may include entities or assets that we would have been interested in acquiring. Therefore, OTA and the Oiltanking Group may compete with us for investment opportunities and OTA and the Oiltanking Group may own an interest in entities that compete with us.
Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and OTA. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its IDRs, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.
Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%, in addition to distributions paid on its 2.0% general partner interest) for each of the prior four consecutive whole fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution as the current target distribution levels.
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and a general partner interest necessary to maintain its general partner interest in us immediately prior to the reset election. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an average aggregate quarterly cash distribution in such prior two quarters equal to the average of the distributions to our general partner on the IDRs in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units trade.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by OTA, as a result of it owning our general partner, and not by our unitholders. Unlike publicly traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
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Even if holders of our common units are dissatisfied, they cannot remove our general partner without its consent.
If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders will be unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all our outstanding common and subordinated units voting together as a single class is required to remove our general partner. OTA owns, directly or indirectly, an aggregate of 66.0% of our common and subordinated units. Also, if our general partner is removed without cause during the subordination period and no units held by the holders of our subordinated units or their affiliates are voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with their own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.
Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. OTA owns, directly or indirectly, an aggregate of 36.1% of our common units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), OTA will own 66.0% of our common units.
We may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:
• | our existing unitholders’ proportionate ownership interest in us will decrease; |
• | the amount of cash available for distribution on each unit may decrease; |
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• | because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; |
• | the ratio of taxable income to distributions may increase; |
• | the relative voting strength of each previously outstanding unit may be diminished; and |
• | the market price of the common units may decline. |
The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by OTA or other large holders.
We have 22,049,901 common units and 19,449,901 subordinated units outstanding. All of the 19,449,901 subordinated units will convert into common units on a one-for-one basis at the end of the subordination period. Sales by OTA or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have provided registration rights to OTA. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.
Payments due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such payments will be determined by our general partner.
Prior to making any distribution on the common units, we reimburse our general partner and its affiliates pursuant to the Services Agreement. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us but does not otherwise limit the amount of expenses for which our general partner and its affiliates may be compensated. Under the Services Agreement, we have an agreed upon fixed fee associated with certain specified selling, general and administrative services necessary to run our business that are provided to us by OTA. These expenses include expenses of non-executive employees, including general and administrative overhead costs, salary, bonus, incentive compensation and other compensation amounts and executive officer expenses, including general and administrative overhead costs, salary, bonus, incentive compensation and other compensation amounts. The compensation for expenses and payment of fees to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our unitholders.
The amount of cash we have available for distribution to holders of our units depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses for financial accounting purposes and may not pay cash distributions during periods when we record net income.
While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.
While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership
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agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by OTA) after the subordination period has ended. OTA owns, directly or indirectly, approximately 36.1% of the outstanding common units and all of our outstanding subordinated units.
Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (“Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
It may be determined that the right, or the exercise of the right by the limited partners as a group, to (i) remove or replace our general partner, (ii) approve some amendments to our partnership agreement or (iii) take other action under our partnership agreement constitutes “participation in the control” of our business. A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner.
The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement.
Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate
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distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to you.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.
Unitholders will be required to pay taxes on their share of our income even if the unitholder does not receive any cash distributions from us.
Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability which results from that income.
Oiltanking Beaumont Specialty Products, LLC (“OTBSP”), one of our subsidiaries, conducts activities that may not generate qualifying income. If the income generated by this subsidiary disproportionately increases as a percentage of our total gross income, we may choose to have this subsidiary treated as a corporation for U.S. federal income tax purposes.
In order to maintain our status as a partnership for U.S. federal income tax purposes, 90% or more of our gross income in each tax year must be qualifying income under Section 7704 of the Internal Revenue Code. A small portion of our current business relates to the transportation and storage of specialty products that may not generate qualifying income. In an attempt to ensure that 90% or more of our gross income in each tax year is qualifying income, we conduct the portion of our business related to these specialty products in OTBSP. Currently, this subsidiary represents approximately 5% of our total gross income. If the income generated by this subsidiary disproportionately increases as a percentage of our total gross income, we may choose to have this subsidiary treated as a corporation for U.S. federal income tax purposes. In such case, this subsidiary would be subject to corporate-level tax on its taxable income at the applicable federal corporate income tax rate (currently, 35%). Imposition of a corporate level tax would reduce the anticipated cash available for distribution to us from OTBSP’s assets and operations and, in turn, would reduce our cash available for distribution to our unitholders. Moreover, if the IRS were to successfully assert that this subsidiary had more tax liability than we currently anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.
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The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. OTA owns, directly and indirectly, more than 50% of the total interests in our capital and profits interests. Therefore, a transfer by OTA of all or a portion of its interests in us could result in a termination of our partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for federal income tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS recently announced a relief procedure whereby if a publicly-traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income result in a decrease in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as “IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Allocations and/or distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest applicable effective tax rate applicable to non-U.S. persons, and each non-U.S. person will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to unitholders.
The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
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We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed Treasury Regulations that proved a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to successfully challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Information regarding our properties is contained in “Item 1. Business — Assets and Areas of Operations” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Item 3. Legal Proceedings
In the ordinary course of business, we may be involved in various claims and legal proceedings, some of which are covered in whole or in part by insurance. We may not be able to predict the timing or outcome of these or future
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claims and proceedings with certainty, and an unfavorable resolution of one or more of such matters could have a material adverse effect on our results of operations, financial condition or cash flows. Currently, we are not party to any legal proceedings that, individually or in the aggregate, are reasonably expected to have a material adverse effect on our results of operations, financial condition or cash flows.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Market Information
Our common units are listed and traded on the NYSE under the symbol “OILT.” The following table sets forth the high and low sales prices per unit for our common units on the NYSE and the cash distributions declared for the periods indicated:
Common Unit Price Range | Distribution per common and subordinated unit (1) | |||||||||||||
2013 | High | Low | Record Date | Payment Date | ||||||||||
4th Quarter | $ | 65.99 | $ | 50.73 | $0.47 | February 3, 2014 | February 14, 2014 | |||||||
3rd Quarter | $ | 52.73 | $ | 46.68 | $0.445 | November 1, 2013 | November 14, 2013 | |||||||
2nd Quarter | $ | 53.97 | $ | 46.50 | $0.425 | August 2, 2013 | August 14, 2013 | |||||||
1st Quarter | $ | 53.20 | $ | 38.01 | $0.405 | May 3, 2013 | May 14, 2013 | |||||||
2012 | ||||||||||||||
4th Quarter | $ | 38.60 | $ | 33.11 | $0.39 | February 1, 2013 | February 14, 2013 | |||||||
3rd Quarter | $ | 41.13 | $ | 30.74 | $0.375 | November 2, 2012 | November 14, 2012 | |||||||
2nd Quarter | $ | 31.96 | $ | 27.65 | $0.36 | August 3, 2012 | August 14, 2012 | |||||||
1st Quarter | $ | 32.93 | $ | 26.57 | $0.35 | May 3, 2012 | May 14, 2012 | |||||||
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(1) | Cash distributions for a quarter are declared and paid in the following quarter. See below for a discussion of our policy regarding distribution payments. |
As of the close of business on February 20, 2014, based upon information received from our transfer agent and brokers and nominees, there were approximately six unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We have also issued 19,449,901 subordinated units, for which there is no established public trading market. All of the subordinated units are held by affiliates of our general partner. Our general partner and its affiliates receive quarterly distributions on these units only after the minimum quarterly distribution has been paid to the holders of our common units.
We are a publicly traded partnership and are not subject to federal income tax. Instead, unitholders are required to report their allocable share of our income, gain, loss and deduction, regardless of whether we make distributions.
Under the terms of the agreements governing our debt, we are required to maintain certain financial ratios, and in order to comply with these covenants, we may be restricted in our ability to declare or pay distributions to unitholders. As of December 31, 2013, we are in compliance with all of these covenants. See “Item 7. Management’s Discussion
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and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for further information.
Selected Information from Our Partnership Agreement
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions, minimum quarterly distributions and IDRs.
Available Cash
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. Our partnership agreement generally defines available cash as, for each quarter, cash generated from our business in excess of the amount of cash reserves established by our general partner to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the next four quarters. Our available cash also may include, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter. Working capital borrowings generally include borrowings made under a credit agreement, commercial paper facility or similar financing arrangement.
Cash Reserves
Our partnership agreement requires our general partner’s board of directors determine in its reasonable discretion the amount of cash reserves to deduct from available cash. In addition, the partnership agreement permits our general partner’s board of directors to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. Any such cash reserves will reduce the amount of cash currently available for distribution to our unitholders.
Minimum Quarterly Distribution
Our partnership agreement provides that, during the subordination period, holders of the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.3375 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution (“MQD”), plus any arrearages in the payment of the MQD to holders of the common units from prior quarters, before any distributions of available cash from operating surplus may be made to holders of the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, holders of the subordinated units will not be entitled to receive any distributions from operating surplus until holders of the common units have received the MQD plus any arrearages in the payment of the MQD from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient available cash from operating surplus to pay the MQD on the common units.
Our partnership agreement provides that the subordination period will expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending September 30, 2014, if each of the following has occurred:
• | distributions of available cash from “operating surplus” (as defined in our partnership agreement) on each of the outstanding common and subordinated units and the general partner interest equaled or exceeded the MQD for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; |
• | the “adjusted operating surplus” (as defined in our partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the MQD on all of the outstanding common and subordinated units and the general partner interest during those periods on a fully diluted weighted-average basis; and |
• | there are no arrearages in payment of the MQD on the common units. |
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As of December 31, 2013, we have made distributions of available cash from operating surplus and generated adjusted operating surplus sufficient to satisfy the subordination tests set forth in the first two bullet points above for the four quarter periods ended September 30, 2012 and September 30, 2013 and, on a pro rata basis for the quarter ending December 31, 2013, and there are no outstanding arrearages on the common units. If we continue to pay distributions from available cash and generate operating surplus at a rate consistent with these prior periods, the subordination period is expected to end following our payment of the distribution for the quarter ending September 30, 2014.
General Partner Interest and IDRs
Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require our general partner to fund its capital contribution with cash and our general partner may fund its capital contribution with common units or other property.
Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:
Target Quarterly Distribution Target Amount | Marginal Percentage Interest in Distributions | ||||
Unitholders | General Partner | ||||
Minimum quarterly distribution | $0.3375 | 98.0% | 2.0% | ||
First target distribution | above $0.3375 up to $0.38813 | 98.0% | 2.0% | ||
Second target distribution | above $0.38813 up to $0.42188 | 85.0% | 15.0% | ||
Third target distribution | above $0.42188 up to $0.50625 | 75.0% | 25.0% | ||
Thereafter | above $0.50625 | 50.0% | 50.0% | ||
The table above assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and our general partner continues to own the IDRs. The maximum distribution sharing percentage of 50.0% includes distributions paid to the general partner on its 2.0% general partner interest and does not include any distributions that the general partner may receive on common units that it owns or may acquire. Our general partner holds all of our IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.
Issuer Purchases and Unregistered Sales of Equity Securities
None.
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Item 6. Selected Financial Data
The following tables set forth, for the periods and at the dates indicated, our selected consolidated financial data for each of the last five years. The consolidated financial data presented as of and for the years ended December 31, 2013, 2012, 2011, 2010 and 2009 are derived from our audited historical consolidated financial statements. Our financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). The tables should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Report (in thousands, except per unit amounts).
Year Ended December 31, | |||||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
Income Statement Data: | |||||||||||||||||||
Revenue | $ | 210,950 | $ | 135,497 | $ | 117,377 | $ | 116,450 | $ | 100,840 | |||||||||
Operating expenses | 43,910 | 36,025 | 31,862 | 32,415 | 29,158 | ||||||||||||||
Selling, general and administrative expenses | 21,765 | 18,856 | 17,985 | 15,775 | 13,830 | ||||||||||||||
Depreciation and amortization expense | 20,407 | 15,901 | 15,676 | 15,579 | 14,191 | ||||||||||||||
(Gain) loss on disposal of fixed assets | (329 | ) | 13 | 544 | (339 | ) | 96 | ||||||||||||
Gain on property casualty indemnification (1) | (303 | ) | — | (928 | ) | (4,688 | ) | — | |||||||||||
Loss on impairment of assets | — | — | — | 46 | 155 | ||||||||||||||
Operating income (1) | 125,500 | 64,702 | 52,238 | 57,662 | 43,410 | ||||||||||||||
Interest expense | (7,393 | ) | (1,654 | ) | (5,438 | ) | (9,538 | ) | (8,401 | ) | |||||||||
Loss on early extinguishment of debt (2) | — | — | (6,382 | ) | — | — | |||||||||||||
Income tax (expense) benefit (3) | (1,087 | ) | (576 | ) | 21,506 | (11,483 | ) | (10,482 | ) | ||||||||||
Net income (1) (2) (3) | 117,063 | 62,645 | 62,397 | 37,815 | 25,116 | ||||||||||||||
Net income subsequent to IPO on July 19, 2011 | 23,806 | ||||||||||||||||||
Key Performance Measures: | |||||||||||||||||||
Adjusted EBITDA (4) | 145,275 | 80,616 | 67,530 | 68,260 | 57,852 | ||||||||||||||
General partner’s interest in net income | 22,096 | 1,489 | 476 | ||||||||||||||||
Limited partners’ interest in net income | 94,967 | 61,156 | 23,330 | ||||||||||||||||
Earnings per common unit – basic and diluted (5) | $ | 2.45 | $ | 1.57 | $ | 0.60 | |||||||||||||
Earnings per subordinated unit – basic and diluted (5) | $ | 2.40 | $ | 1.57 | $ | 0.60 | |||||||||||||
Distributions per unit (6) | $ | 1.665 | $ | 1.425 | $ | 0.2678 | |||||||||||||
December 31, | |||||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
Balance Sheet Data: | |||||||||||||||||||
Total assets | $ | 728,974 | $ | 469,220 | $ | 322,035 | $ | 310,469 | $ | 303,500 | |||||||||
Total debt, including current portion | 190,800 | 149,300 | 20,800 | 148,258 | 164,215 | ||||||||||||||
Total partners’ capital | 493,647 | 285,928 | 279,847 | 104,049 | 90,096 | ||||||||||||||
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Year Ended December 31, | |||||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
Cash Flow Data: | |||||||||||||||||||
Net cash flows provided by (used in): | |||||||||||||||||||
Operating activities | $ | 134,301 | $ | 75,254 | $ | 56,376 | $ | 60,678 | $ | 32,253 | |||||||||
Investing activities | (255,971 | ) | (162,527 | ) | (45,304 | ) | (30,191 | ) | (34,469 | ) | |||||||||
Financing activities | 131,931 | 70,508 | 4,018 | (27,597 | ) | 3,243 | |||||||||||||
Capital expenditures | 180,672 | 149,827 | 27,772 | 11,167 | 34,479 | ||||||||||||||
___________
(1) | During the years ended December 31, 2013 and 2011, we recognized gains of $0.3 million and $0.7 million, respectively, from proceeds received for an insurance claim relating to damages sustained from a hurricane in 2008. During the years ended December 31, 2011 and 2010, we recognized gains of $0.2 million and $4.7 million, respectively, from proceeds received for an insurance claim relating to damages sustained during 2008 to a dock that was struck by a vessel owned and operated by a third party. |
(2) | During the year ended December 31, 2011, we recognized a loss of $6.4 million on the repayment of debt, which was repaid with proceeds from our IPO. |
(3) | Upon the change in tax status in connection with our IPO, during the year ended December 31, 2011, we recognized a non-recurring gain of $27.1 million related to the elimination of the deferred tax account balances. |
(4) | Adjusted EBITDA is not a presentation made in accordance with GAAP. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Adjusted EBITDA” for a reconciliation of Adjusted EBITDA from net income. |
(5) | The 2011 amounts represent basic and diluted earnings per unit for the period from July 19, 2011 (the closing of our IPO) through December 31, 2011. |
(6) | Beginning with the quarter ended September 30, 2011, we distributed all of our available cash to unitholders of record on the applicable record date in accordance with our partnership agreement. The MQD of $0.3375 was pro-rated for the period beginning after July 19, 2011 (the closing of our IPO) through September 30, 2011. |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following information should be read in conjunction with our consolidated financial statements and our accompanying notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this Report. Our discussion and analysis includes the following:
• | Overview of Business; |
• | General Outlook for 2014; |
• | 2013 Developments and Updates — discusses major items impacting our results in 2013; |
• | Results of Operations — discusses material year-to-year variances in the consolidated statements of income; |
• | Liquidity and Capital Resources — addresses available sources of liquidity and capital resources and includes a discussion of our capital spending; |
• | Critical Accounting Policies and Estimates — presents accounting policies and estimates that are among the most critical to the presentation of our financial position and results of operations; and |
• | Other Considerations — includes information related to contractual obligations, off-balance sheet arrangements and related party transactions. |
This discussion contains forward-looking statements based on current expectations that are subject to risks and uncertainties, such as statements of our plans, objectives, expectations and intentions. Our actual results and the timing of events could differ materially from those anticipated or implied by the forward-looking statements discussed in this Report as a result of various factors, including, among others, those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” herein. Oiltanking GmbH and its subsidiaries, other than OILT and its subsidiaries, are collectively referred to herein as the “Oiltanking Group.” As used in this document, the terms “we,”
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“us,” and “our” and similar terms refer to OILT and its subsidiaries, where applicable, unless the context indicates otherwise.
Overview of Business
We are a growth-oriented limited partnership engaged in the independent terminaling, storage and transportation of crude oil, refined petroleum products and LPG. We provide services to major integrated oil companies, distributors, marketers and chemical and petrochemical companies, typically under long-term commercial agreements that include minimum volume commitments and inflation escalators. We do not take ownership of the crude oil, refined products or LPG that we terminal, store or transport nor do we engage in any marketing or trading of commodities.
Our primary business objectives are to generate stable and predictable cash flows to enable us to pay quarterly distributions to our unitholders and to increase our quarterly cash distributions per unit over time. We intend to achieve these objectives by anticipating long-term infrastructure needs in the areas we serve and by growing our tank terminals and pipeline networks through construction in new markets, the expansion of existing facilities and strategic acquisitions.
At December 31, 2013, we had nearly 22 million barrels of total active storage capacity at our Houston and Beaumont facilities. These integrated facilities are strategically located and directly connected to 23 key refining, production and storage facilities along the Gulf Coast and the Cushing, Oklahoma storage interchange through dedicated and common carrier pipelines. In addition, our facilities provide our customers deep-water access and international distribution capabilities.
Our Houston terminals serve as a regional hub for crude oil and other feedstocks for refineries and petrochemical facilities located in the Gulf Coast region and also serve as important export facilities for LPG and other refined petroleum products. At December 31, 2013, this facility had an aggregate active storage capacity of approximately 16.2 million barrels. Our Beaumont terminal serves as a regional hub for refined petroleum products for refineries located in the Gulf Coast region. At December 31, 2013, this facility had an aggregate active storage capacity of approximately 5.5 million barrels.
General Outlook for 2014
We believe there will continue to be growth in North American crude oil, natural gas and natural gas liquid (“NGL”) production in 2014 due to shale drilling and advances in drilling technology. In particular, we expect sustained growth in onshore domestic crude oil production from the Permian, Eagle Ford, Bakken and other shale plays, and increasing offshore production from the Gulf of Mexico.
Announced and completed pipeline expansion projects are expected to result in a significant increase in crude oil supplies to the Gulf Coast. Although the crude oil being produced and imported to the U.S. consists of many different grades and blends, the majority of Gulf Coast refiners have invested significantly in infrastructure to process heavy crudes as a primary feedstock. A substantial proportion of new production volumes being shipped to the Gulf Coast market has been medium and light sweet crudes and condensates. As a result, regional supply and demand imbalances have arisen and are expected to persist. These imbalances create incremental demand for crude oil to be staged, batched or segregated to allow our customers to optimize the revenues received for their products. The ability to export crude by water to the extent permitted under the current regulatory environment also provides potential outlets to more attractive markets. Handling the diversity of crude types often necessitates additional fee-based services, such as blending and heating. The changing crude oil logistics landscape should continue to drive increased demand for our storage and transportation services and create opportunities for us to use our existing assets and to develop additional infrastructure to meet the growing needs of our customers.
In addition, we anticipate the unprecedented growth in NGL production as result of crude oil and natural gas production to continue. This growth has contributed to significant capital investments in the natural gas processing and fractionating sectors. NGL supply has exceeded domestic demand, creating a surplus of LPG, particularly in the Gulf Coast. LPG exports have helped balance U.S. supply and demand. We expect continued strong demand for the handling and export of LPG from our Houston terminal over the next several years.
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We believe our stable asset base, long-term contract profile, conservative financial leverage and economically attractive expansion projects should enable us to continue to grow our cash flows for the next several years. We also believe we are reasonably well positioned to pursue and consummate acquisitions. There can be no assurance that these opportunities will come to fruition or our acquisition and expansion efforts will be successful.
We believe that cash on hand, proceeds expected to be received on our short-term notes receivable, cash flow in excess of distributions, as well as borrowings under our undrawn Credit Agreement or other long-term debt agreements with OT Finance will enable us to fund our currently anticipated expansion activities for the next several years. However, funding of additional expansion activities or acquisitions may require us to access additional capital resources, which we intend to fund with a balanced combination of equity and debt capital. Although we believe that equity and debt markets will be available to us on reasonable terms based on current market conditions, there can be no assurance that future market conditions will permit us to access capital to fund future acquisition and expansion activities. See “Item 1A. Risk Factors — Risks Inherent in Our Business.”
2013 Developments and Updates
Significant financial highlights during the year ended December 31, 2013, included the following:
• | On June 26, 2013, OTH entered into the $50.0 million Loan Agreement for the purpose of financing the purchase of property, plant and equipment, with a maturity date of June 30, 2023. At December 31, 2013, OTH had $50.0 million of outstanding borrowings under this loan agreement at a fixed interest rate of 5.435% per annum. |
• | In August 2013, the Conflicts Committee of the board of directors of our general partner approved a requested increase to the fixed fee charged to us under the Services Agreement from $15.1 million to $18.8 million on an annualized basis to reflect higher selling, general and administrative expenses associated with expansion projects placed in service in 2013. The fee increase was effective as of July 1, 2013. |
• | On November 22, 2013, we completed a public offering of 2,600,000 common units at a price to the public of $61.65 per unit. The proceeds from the offering, net of underwriting discounts and other offering expenses, totaled approximately $154.3 million. In connection with the offering, our general partner contributed an additional $3.3 million to us to maintain its 2.0% general partner interest in us. We used $56.0 million of the proceeds to repay the balance outstanding under our Credit Agreement. |
• | We increased our quarterly distribution to $0.47 per unit for the fourth quarter of 2013, representing a 20.5% increase over the distribution for the fourth quarter of 2012, and our ninth consecutive quarterly increase since becoming a public company in the third quarter of 2011. |
Significant operational highlights during the year ended December 31, 2013, included the following:
• | During January 2013, we placed into service a pipeline expansion project in Houston announced in November 2011. |
• | In February 2013, we placed into service three new crude oil storage tanks with a total capacity of 825,000 barrels at our Houston terminal. The final 275,000 barrel tank of that four tank expansion project was placed into service in July 2013. |
• | During the first quarter of 2013, we completed construction and placed into service two new refined products storage tanks in Beaumont, with a total capacity of 320,000 barrels. |
• | In March 2013, we announced an expansion of our relationship with Enterprise and plans to increase our ability to export LPG at our terminal on the Houston Ship Channel. In connection with the agreement with Enterprise, we are constructing a new vessel dock and adding infrastructure to existing docks with the capability of handling substantially more LPG vessels. The estimated $44.0 million expansion project is expected to be completed by the end of 2014. Pursuant to this agreement, we were initially entitled to participate in margin sharing with Enterprise on only a portion of the customer vessels loaded at our Houston facility; however, in July 2013, we triggered a contractual provision that entitled us to participate in margin sharing on all customer vessels loaded at our Houston facility after January 2014. In January |
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2014, we announced another expansion of this agreement, which is described under “Item 1. Business — 2013 and Recent Developments — LPG Export Terminal Agreement and Dock Expansion Project.”
• | During 2013, as part of our Appelt I expansion, we placed into service nine new crude oil storage tanks with a total capacity of 2,970,000 barrels. In January 2014, we completed the Appelt I project by placing the remaining storage tank with a total capacity of 210,000 barrels into service. |
• | In November 2013, we announced approval of expansion projects of approximately $101.0 million to construct approximately 3.5 million barrels of additional crude oil storage capacity near our Houston terminal at our Appelt property. One of these projects includes a new 390,000 barrel storage tank to be connected to the Appelt I and Appelt II manifolds that is expected to be completed by the end of 2014. The remaining additional storage capacity of approximately 3.1 million barrels consists of nine tanks to be constructed on 26 acres of land adjacent to our ongoing Appelt II expansion. The 3.1 million barrel Appelt III project would include a new manifold, and, upon completion, would bring total storage capacity at our Appelt property to approximately 10.0 million barrels. The new storage capacity at Appelt III is expected to be placed into service during the fourth quarter of 2015 and first quarter of 2016. |
• | In November 2013, we announced approval of expansion projects of approximately $98.0 million to construct two new crude oil pipelines connecting our Houston facility with Crossroads Junction, which is the termination point of the Houston lateral of TransCanada Corporation’s Gulf Coast Pipeline from Cushing and the origination point of Shell Pipeline’s HoHo Pipeline. The expansion projects include a new 24-inch pipeline and a new 36-inch pipeline. The 24-inch pipeline is expected to be completed by the end of 2014, and the 36-inch pipeline is expected to be completed by the end of the first quarter of 2015. |
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Results of Operations
Our operating results were as follows for the periods indicated (in thousands, except per unit amounts):
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Revenues | $ | 210,950 | $ | 135,497 | $ | 117,377 | |||||
Costs and expenses: | |||||||||||
Operating | 43,910 | 36,025 | 31,862 | ||||||||
Selling, general and administrative | 21,765 | 18,856 | 17,985 | ||||||||
Depreciation and amortization | 20,407 | 15,901 | 15,676 | ||||||||
(Gain) loss on disposal of fixed assets | (329 | ) | 13 | 544 | |||||||
Gain on property casualty indemnification | (303 | ) | — | (928 | ) | ||||||
Total costs and expenses | 85,450 | 70,795 | 65,139 | ||||||||
Operating income | 125,500 | 64,702 | 52,238 | ||||||||
Other income (expense): | |||||||||||
Interest expense | (7,393 | ) | (1,654 | ) | (5,438 | ) | |||||
Loss on early extinguishment of debt | — | — | (6,382 | ) | |||||||
Interest income | 30 | 33 | 42 | ||||||||
Other income | 13 | 140 | 431 | ||||||||
Total other expense, net | (7,350 | ) | (1,481 | ) | (11,347 | ) | |||||
Income before income tax (expense) benefit | 118,150 | 63,221 | 40,891 | ||||||||
Income tax (expense) benefit | (1,087 | ) | (576 | ) | 21,506 | ||||||
Net income | $ | 117,063 | $ | 62,645 | $ | 62,397 | |||||
Earnings per common unit – basic and diluted (1) | $ | 2.45 | $ | 1.57 | $ | 0.60 | |||||
Earnings per subordinated unit – basic and diluted (1) | $ | 2.40 | $ | 1.57 | $ | 0.60 | |||||
______________
(1) | Amounts attributable to 2011 are reflective of general and limited partner interest in net income subsequent to the closing of our IPO on July 19, 2011. |
Adjusted EBITDA
We define Adjusted EBITDA as net income (loss) before net interest expense, income tax (expense) benefit, depreciation and amortization expense and other income, as further adjusted to exclude certain other non-cash and non-recurring items, which includes gains and losses on disposal of fixed assets, property casualty indemnification and early extinguishment of debt for the periods presented above. Adjusted EBITDA is a non-GAAP supplemental financial performance measure management and other third parties, such as industry analysts, investors, lenders and rating agencies, may use to assess: (i) our financial performance as compared to our peers, without regard to historical cost basis or financing methods, (ii) the viability of proposed projects and acquisitions and (iii) the rates of return on investment in various opportunities. Accordingly, we believe the presentation of Adjusted EBITDA provides useful information to investors in assessing our results of operations.
The GAAP measure most directly comparable to Adjusted EBITDA is net income. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP measures, such as net income, operating income, cash flow from operating activities or any other GAAP measure of financial performance. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of
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Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
The following table presents a reconciliation of Adjusted EBITDA from net income, the most directly comparable GAAP financial measure, for the periods indicated (in thousands):
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Reconciliation of Adjusted EBITDA from net income: | |||||||||||
Net income | $ | 117,063 | $ | 62,645 | $ | 62,397 | |||||
Depreciation and amortization | 20,407 | 15,901 | 15,676 | ||||||||
Income tax expense (benefit) | 1,087 | 576 | (21,506 | ) | |||||||
Interest expense, net | 7,363 | 1,621 | 5,396 | ||||||||
Loss on early extinguishment of debt | — | — | 6,382 | ||||||||
(Gain) loss on disposal of fixed assets | (329 | ) | 13 | 544 | |||||||
Gain on property casualty indemnification | (303 | ) | — | (928 | ) | ||||||
Other income | (13 | ) | (140 | ) | (431 | ) | |||||
Adjusted EBITDA | $ | 145,275 | $ | 80,616 | $ | 67,530 | |||||
Operating Data
The following table presents operating data for the periods indicated:
Year Ended December 31, | ||||||||
2013 | 2012 | 2011 | ||||||
Storage capacity, end of period (mmbbls) (1) (3) | 21.7 | 17.7 | 17.3 | |||||
Storage capacity, average (mmbbls) (3) | 19.3 | 17.6 | 16.8 | |||||
Terminal throughput (mbpd) (2) | 1,064.3 | 822.2 | 771.9 | |||||
Vessels per period | 914 | 879 | 823 | |||||
Barges per period | 3,228 | 3,233 | 2,509 | |||||
Trucks per period | 30,910 | 11,307 | 5,158 | |||||
Rail cars per period | 4,914 | 7,979 | 702 | |||||
_______________________
(1) | Represents million barrels (“mmbbls”). |
(2) | Represents thousands of barrels per day (“mbpd”). |
(3) | Amounts do not reflect approximately 210,000 barrels of storage capacity placed into service in January 2014. |
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Adjusted EBITDA. Adjusted EBITDA for the year ended December 31, 2013 increased by $64.7 million, or 80.2%, to $145.3 million from $80.6 million for the year ended December 31, 2012. The increase in Adjusted EBITDA was primarily attributable to a $75.5 million increase in revenues, partially offset by a $7.9 million increase in operating expenses and a $2.9 million increase in selling, general and administrative expenses (“SG&A expenses”).
Revenues. Revenues for the year ended December 31, 2013 increased by $75.5 million, or 55.7%, to $211.0 million from $135.5 million for the year ended December 31, 2012, primarily attributable to an increase in storage service fee revenues of $22.7 million, an increase in throughput fee revenue of $50.6 million and an increase in ancillary services fee revenue of $2.2 million. Increased storage service fee revenues were attributable to additional revenues from approximately 4.1 million barrels of new storage capacity placed into service in the first, third and fourth quarters of 2013, an increase of 22.6% in storage capacity, and, to a lesser extent, due to an escalation of storage fees under our contracts. Increased throughput fee revenue was attributable to an increase in fees related to LPG exports at our Houston
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terminal, which included approximately $30.9 million received under a margin sharing arrangement with our customer that was in addition to volume-based throughput fees and, to a lesser extent, fees generated on pipelines placed into service in the first quarter of 2013.
Operating Expenses. Operating expenses for the year ended December 31, 2013 increased by $7.9 million, or 21.9%, to $43.9 million from $36.0 million for the year ended December 31, 2012. The increase in operating expenses was primarily due to an increase of $2.9 million in operations employee-related costs incurred by OTA and charged to us under the Services Agreement due to increases in benefit costs and higher operational labor costs in the 2013 period, an increase of $2.5 million in property taxes resulting from an increased property base and increased property values, an increase of $2.0 million in repairs and maintenance costs, an increase of $1.2 million in power and fuel costs due to higher fuel usage, an increase of $0.9 million in insurance costs due to policy renewals with higher premiums and an increase of $0.1 million in legal, permitting and licensing fees. These increases in operating expenses were partially offset by a decrease of $1.4 million in expenses associated with a pipeline-related construction project which was completed in 2012 and decrease of $0.2 million in rental expense due to the purchase of previously leased land for our expansion projects.
Selling, General and Administrative Expenses. SG&A expenses for the year ended December 31, 2013 increased by $2.9 million, or 15.4%, to $21.8 million from $18.9 million for the year ended December 31, 2012. The increase in SG&A expenses was primarily due to an increase of $0.9 million in the quarterly fixed fee under an amendment to the Services Agreement effective July 1, 2013. See Note 3 in the Notes to Consolidated Financial Statements. SG&A expenses also increased as a result of higher legal, accounting and professional fees in 2013.
Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2013 increased by $4.5 million, or 28.3%, to $20.4 million from $15.9 million for the year ended December 31, 2012, primarily due to assets placed in service in 2012 and 2013.
(Gain) Loss on Disposal of Fixed Assets. During the year ended December 31, 2013, we recognized a gain of $0.3 million on the dismantling and disposal of terminal assets, which were not part of our active storage capacity. During the year ended December 31, 2012, we recognized a loss of less than $0.1 million on the disposal of certain dismantled terminal assets.
Gain on Property Casualty Indemnification. During the year ended December 31, 2013, we recognized a gain of $0.3 million from proceeds received for an insurance claim related to damages sustained during a hurricane in 2008.
Interest Expense. Interest expense for the year ended December 31, 2013 increased by $5.7 million, or 347.0%, to $7.4 million from $1.7 million for the year ended December 31, 2012, primarily due to higher outstanding borrowings during 2013 under our long-term debt agreements driven by increased construction activity, partially offset by higher capitalized interest on construction projects.
Income Tax Expense. Income tax expense for the year ended December 31, 2013 increased by $0.5 million, or 88.7%, to $1.1 million from $0.6 million for the year ended December 31, 2012, due to an increase in accruals for Texas margin tax. Due to our status as a partnership, we and our subsidiaries are not subject to U.S. federal or state income taxes, with the exception of Texas margin tax.
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Adjusted EBITDA. Adjusted EBITDA for the year ended December 31, 2012 increased by $13.1 million, or 19.4%, to $80.6 million from $67.5 million for the year ended December 31, 2011. The increase in Adjusted EBITDA was primarily attributable to an $18.1 million increase in revenues, partially offset by a $4.2 million increase in operating expenses and a $0.9 million increase in SG&A expenses.
Revenues. Revenues for the year ended December 31, 2012 increased by $18.1 million, or 15.4%, to $135.5 million from $117.4 million for the year ended December 31, 2011. The increase in revenues was primarily attributable to additional revenues from the new storage capacity placed into service in December 2011 and in April 2012 and an
47
escalation in storage fees, resulting in an increase in storage revenues of $9.8 million, higher throughput fee revenue of $5.1 million, primarily attributable to increased LPG exports during 2012 and an increase in ancillary services fee revenue of $3.2 million, approximately $1.4 million of which relates to revenues from a pipeline-related construction project for a customer that was completed and recognized during 2012.
Operating Expenses. Operating expenses for the year ended December 31, 2012 increased by $4.2 million, or 13.1%, to $36.0 million from $31.9 million for the year ended December 31, 2011. The increase in operating expenses was primarily due to an increase of $2.3 million in operations employee-related costs incurred by OTA and charged to us under the Services Agreement due to increases in benefit costs and higher operational labor in the 2012 period, an increase of $1.9 million in legal, engineering and permitting and licensing fees, an increase of $1.4 million in expenses associated with the pipeline-related construction project discussed above and an increase of $0.3 million in insurance costs. These increases in operating expenses were partially offset by a decrease of $1.2 million in power and fuel costs due to re-negotiated power rates at a lower rate and a decrease of $0.5 million in rental expense due to the purchase of previously leased land for our expansion projects.
Selling, General and Administrative Expenses. SG&A expenses for the year ended December 31, 2012 increased by $0.9 million, or 4.8%, to $18.9 million from $18.0 million for the year ended December 31, 2011. The increase in SG&A expenses in the 2012 period was primarily due to additional costs of operating as a publicly traded partnership for the full year in 2012, as compared to only a portion of the year ended December 31, 2011.
Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2012 increased by $0.2 million, or 1.4%, to $15.9 million from $15.7 million for the year ended December 31, 2011, primarily due to assets placed in service in late 2011 and in 2012.
Loss on Disposal of Fixed Assets. During the years ended December 31, 2012 and 2011, we recognized losses of less than $0.1 million and approximately $0.5 million, respectively, on the disposal of certain terminal assets that were dismantled.
Gain on Property Casualty Indemnification. During the year ended December 31, 2012, we did not recognize any gain or loss from property casualty indemnification. During the year ended December 31, 2011, we recognized a gain of $0.9 million, of which $0.7 million was for an insurance claim related to damages sustained during a hurricane in 2008 and $0.2 million was from proceeds received for an insurance claim resulting from property damages which occurred in 2008 to a dock at our Beaumont terminal.
Interest Expense. Interest expense for the year ended December 31, 2012 decreased by $3.8 million, or 69.6%, to $1.7 million from $5.4 million for the year ended December 31, 2011, primarily due to lower outstanding borrowings as a result of the repayment of notes payable to an affiliate with proceeds from our IPO in July 2011, and higher capitalized interest on construction projects.
Loss on Early Extinguishment of Debt. During the year ended December 31, 2012, we did not recognize any loss on early extinguishment of debt. During the year ended December 31, 2011, we recognized a $6.4 million loss on early extinguishment of debt, attributable to a reimbursement paid to OT Finance for fees incurred in connection with the repayment of $119.5 million of outstanding amounts under our notes payable, affiliate, with the proceeds of our IPO.
Income Tax (Expense) Benefit. Income tax expense for the year ended December 31, 2012 was $0.6 million, compared to an income tax benefit of $21.5 million for the year ended December 31, 2011, a net change of $22.1 million. The net change was primarily attributable to the change in the tax status of OTH in connection with our IPO in July 2011. In July 2011, OTH elected to be treated as a disregarded entity for U.S. federal income tax purposes. See Note 7 in the Notes to Consolidated Financial Statements. Upon the change in the tax status of OTH, we recognized a non-recurring income tax benefit of $27.1 million related to the elimination of the deferred tax account balances.
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Liquidity and Capital Resources
Liquidity
Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, service our debt and pay distributions to our partners. Our sources of liquidity may include cash generated by our operations, loans from OT Finance, borrowings under our Credit Agreement and issuances of equity and debt securities. We believe cash generated from these sources will be sufficient to meet our obligations as they come due for the foreseeable future.
On November 22, 2013, we completed a public offering of 2,600,000 common units at a price to the public of $61.65 per unit. The proceeds from the offering, net of underwriting discounts and other offering expenses, totaled approximately $154.3 million. In connection with the offering, our general partner contributed an additional $3.3 million to us to maintain its 2.0% general partner interest in us.
During the year ended December 31, 2013, we paid cash distributions to unitholders totaling $66.9 million, or $1.665 per unit, and corresponding distributions on our general partner’s interest and IDRs. On January 21, 2014, we announced that the board of directors of our general partner declared a cash distribution to our unitholders of $0.47 per unit for the fourth quarter of 2013, and corresponding distributions on our general partner’s interest and IDRs. The fourth quarter 2013 cash distribution totaling approximately $20.7 million was paid on February 14, 2014 to unitholders of record at the close of business on February 3, 2014. The fourth quarter 2013 cash distribution represents a 5.6% increase over the third quarter 2013 cash distribution of $0.445 per unit and a 20.5% increase over the fourth quarter of 2012 cash distribution of $0.39 per unit. We intend to continue to pay quarterly distributions on our outstanding partnership interests to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates.
In April 2012, we announced approval of our Appelt I expansion project, a $104.0 million project to construct approximately 3.2 million barrels of new crude oil storage capacity near our Houston terminal. During 2013, as part of our Appelt I expansion, we placed into service nine new crude oil storage tanks with a total capacity of 2,970,000 barrels. In January 2014, we completed the Appelt I project by placing 210,000 barrels of storage capacity into service.
In September 2012, we announced approval of our Appelt II expansion project, a $70.0 million project to construct approximately 3.3 million barrels of new crude oil storage capacity, adjacent to our ongoing Appelt I project. This additional storage capacity is expected to be placed into service during the third and fourth quarters of 2014.
In March 2013, we announced an expansion of our relationship with Enterprise and plans to increase our ability to import and export LPG at our terminal on the Houston Ship Channel. In connection with the agreement with Enterprise, we announced a $44.0 million expansion project to construct a new vessel dock and add infrastructure to existing docks. The dock expansion project is expected to be completed by the end of 2014. In January 2014, we announced a further expansion of our terminal service agreement with Enterprise to handle increased volumes of LPG exports at our Houston terminal. Under the amended agreement, the primary contract term was extended to 50 years from the February 1, 2014 effective date, and the exclusivity provisions relating to the Houston Ship Channel in the prior agreement were expanded to cover all of the U.S. Gulf Coast. The throughput rates and margin sharing provisions in the amended agreement remain unchanged from the prior terminal service agreement.
In November 2013, we announced approval of expansion projects of approximately $101.0 million to construct approximately 3.5 million barrels of additional crude oil storage capacity near our Houston terminal at our Appelt property. One of these projects includes a new 390,000 barrel storage tank expected to be completed by the end of 2014. We anticipate commencing construction on the remaining 3.1 million barrels during the third quarter of 2014, and placing these tanks into service during the fourth quarter of 2015 and first quarter of 2016.
In November 2013, we announced approval of expansion projects of approximately $98.0 million to construct two new crude oil pipelines connecting our Houston facility with Crossroads Junction, which is the termination point of the Houston lateral of TransCanada Corporation’s Gulf Coast Pipeline from Cushing and the origination point of the
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HoHo Pipeline. The expansion projects include a new 24-inch pipeline that will give our terminal customers direct access to the origination point of the HoHo Pipeline, which is expected to transport crude oil from the Houston area eastbound to refining centers in Texas and Louisiana. The expansion projects also include a new 36-inch pipeline that will give our terminal customers access to the termination point of TransCanada Corporation’s Gulf Coast Pipeline, which is expected to connect to the Keystone XL pipeline if approved and constructed. The 24-inch pipeline is expected to be completed by the end of 2014, and the 36-inch pipeline is expected to be completed by the end of the first quarter of 2015.
Of the $417.0 million of total expected capital spending for the projects discussed above, approximately $187.5 million has been spent through December 31, 2013. We anticipate funding the remainder of these projects and other capital spending primarily with cash on hand and long-term borrowings from OT Finance.
OTH Loan Agreements
OTH has a ten-year, $125.0 million unsecured loan agreement with OT Finance (the “$125.0 million Loan Agreement”) for the purpose of financing the purchase of property, plant and equipment, with a maturity date of December 15, 2022. At December 31, 2013, OTH had $125.0 million of outstanding borrowings under this loan agreement at a fixed interest rate of 4.55% per annum.
On June 26, 2013, OTH entered into the $50.0 million Loan Agreement with OT Finance for the purpose of financing the purchase of property, plant and equipment, with a maturity date of June 30, 2023. At December 31, 2013, OTH had $50.0 million of outstanding borrowings under this loan agreement at a fixed interest rate of 5.435% per annum.
For additional information on the $125.0 million Loan Agreement and the $50.0 million Loan Agreement, see Note 8 in the Notes to Consolidated Financial Statements.
OILT Credit Agreement
Our Credit Agreement with OT Finance, which we amended in November 2012, is a $150.0 million credit agreement, with a maturity date of November 30, 2017. From time to time upon our written request and in the sole determination of OT Finance, the revolving credit commitment can be increased up to an additional $75.0 million, for a maximum revolving credit commitment of $225.0 million. Borrowings bear interest at the London Interbank Offered Rate (“LIBOR”) plus a margin ranging from 1.65% to 2.50% depending upon a leverage-based grid. Any unused portion of the revolving line of credit is subject to a commitment fee of 0.35% per annum. In November 2013, we repaid $56.0 million outstanding under the Credit Agreement with proceeds from our public equity offering. See Note 9 in the Notes to Consolidated Financial Statements. As of December 31, 2013, OILT had no borrowings outstanding under the Credit Agreement.
For additional information on the OILT Credit Agreement, see Note 8 in the Notes to Consolidated Financial Statements.
Potential OTA Financial Support
OTA and other members of the Oiltanking Group, including OT Finance, may elect, but are not obligated, to provide financial support to us under certain circumstances, such as in connection with an acquisition or expansion capital project. Our partnership agreement contains provisions designed to facilitate the Oiltanking Group’s ability to provide us with financial support while reducing concerns regarding conflicts of interest by defining certain potential financing transactions between OTA and other members of the Oiltanking Group, including OT Finance, on the one hand, and us, on the other hand, as fair to our unitholders. In that regard, the following forms of potential Oiltanking Group financial support do not require approval by the Conflicts Committee of the board of directors of our general partner and will be deemed fair to our unitholders, and will not constitute a breach of any fiduciary or other duty owed to us by our general partner, if consummated on terms no less favorable than described below:
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• | our issuance of common units to OTA or any of its affiliates at a price per common unit of no less than 95% of the trailing 10-day average closing price per common unit; |
• | our borrowing of funds from OTA or any of its affiliates on terms that include a term of at least one year and no more than ten years and a fixed rate of interest that is no more than 200 basis points higher than the corresponding base rate, which is LIBOR for one year maturities and the USD swap rate for maturities of greater than one year and up to ten years; and |
• | OTA and its affiliates may provide us with guaranties or trade credit support to support our ongoing operations; provided, that (i) the pricing of any such guaranties or trade credit support is no more than 100 basis points per annum and (ii) any such guaranties or trade credit support are limited to our ordinary course obligations and do not extend to indebtedness for borrowed money or other obligations that could be characterized as debt. |
We have no obligation to seek financing or support from OTA or any other member of the Oiltanking Group on the terms described above or to accept such financing or support if it is offered to us. In addition, neither OTA nor any other member of the Oiltanking Group has any obligation to provide financial support under these or any other circumstances. The existence of these provisions will not preclude other forms of financial support from OTA or any other member of the Oiltanking Group, including financial support on significantly less favorable terms under circumstances in which such support appears to be in our best interests.
In addition, following the completion of our issuance of units in connection with an underwritten public offering, direct placement and/or private offering of units, we may make a reasonably prompt redemption of a number of common units owned by OTA or its affiliates that is no greater than the aggregate number of common units issued to OTA or its affiliates pursuant to the provisions summarized in the first bullet above (taking into account any prior redemption pursuant to the provisions summarized in this paragraph) at a price per common unit that is no greater than the price per common unit paid by the investors in such offering, as applicable, less underwriting discounts and commissions or placement fees, if any. As with the transactions described in the bullets above, any such redemption will be deemed fair to our unitholders and will not constitute a breach of any duty owed to us by our general partner.
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated (in thousands):
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Cash provided by (used in): | |||||||||||
Operating activities | $ | 134,301 | $ | 75,254 | $ | 56,376 | |||||
Investing activities | (255,971 | ) | (162,527 | ) | (45,304 | ) | |||||
Financing activities | 131,931 | 70,508 | 4,018 | ||||||||
Our consolidated statements of cash flows are prepared using the indirect method. The indirect method derives net cash flows from operating activities by adjusting net income to remove (i) the effects of all deferrals of past operating cash receipts and payments, such as changes during the period in deferred income and similar transactions, (ii) the effects of all accruals of expected future operating cash receipts and cash payments, such as changes during the period in receivables and payables, (iii) the effects of all items classified as investing or financing cash flows, such as gains or losses on sale of property, plant and equipment or extinguishment of debt, and (iv) other non-cash amounts such as depreciation and amortization. In general, the net effect of changes in operating accounts results from the timing of cash receipts from customers to settle accounts receivable and cash payments for operating and other expenses during each period.
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Operating Activities
2013 Compared to 2012. Net cash flows provided by operating activities for the year ended December 31, 2013 increased by $59.0 million, or 78.5%, to $134.3 million from $75.3 million for the year ended December 31, 2012. The increase was primarily attributable to an increase in storage service fee revenues, throughput fee revenues and ancillary service fee revenues, partially offset by increased operating and SG&A expenses.
2012 Compared to 2011. Net cash flows provided by operating activities for the year ended December 31, 2012 increased by $18.9 million, or 33.5%, to $75.3 million from $56.4 million for the year ended December 31, 2011. The increase was primarily attributable to an increase in storage service fee revenues, throughput fee revenues and ancillary service fee revenues, partially offset by increased operating and SG&A expenses.
Investing Activities
2013 Compared to 2012. Net cash flows used in investing activities for the year ended December 31, 2013 increased by $93.4 million, or 57.5%, to $256.0 million from $162.5 million for the year ended December 31, 2012. The increase is primarily attributable to an increase in fixed asset purchases of $30.8 million relating to our various expansion projects, the purchase of intangible assets of $3.7 million, partially offset by an increase of $59.3 million in the issuance of notes receivable, net of collections, from OT Finance.
2012 Compared to 2011. Net cash flows used in investing activities for the year ended December 31, 2012 increased by $117.2 million, or 258.7%, to $162.5 million from $45.3 million for the year ended December 31, 2011. The increase is primarily attributable to an increase in fixed asset purchases of $122.1 million relating to our various expansion projects, partially offset by an increase of $5.6 million in the collections, net of issuance, of notes receivable from OT Finance.
Cash paid for capital expenditures were as follows for the periods indicated (in thousands):
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Maintenance capital expenditures | $ | 3,111 | $ | 3,682 | $ | 4,160 | |||||
Expansion capital expenditures | 177,561 | 146,145 | 23,612 | ||||||||
Total capital expenditures | $ | 180,672 | $ | 149,827 | $ | 27,772 | |||||
Maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity. Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity over the long-term. During the years ended December 31, 2013 and 2012, we spent $177.6 million and $146.1 million, respectively, of expansion capital primarily for the continuing construction of the new storage capacity at our Houston area terminals and associated crude oil pipeline infrastructure investments. During the year ended December 31, 2011, we spent $23.6 million of expansion capital primarily for both the completion of a barge dock at our Beaumont terminal and for the continuing construction of and partial completion of storage capacity at our Houston terminal.
We expect to spend approximately $230.0 million to $250.0 million for capital expenditures for the full year of 2014, of which approximately $8.5 million is expected to relate to maintenance capital expenditures and approximately $10.0 million to $15.0 million is expected to relate to upgrades and improvements to our existing infrastructure to increase throughput capacity and increase our ability to provide fee-based services, such as heating and blending. A majority of the capital expenditures projected for 2014 of approximately $190.7 million relates to storage capacity projects at our Houston area terminals (Appelt II and Appelt III), the LPG dock expansion project and the pipeline expansion projects. See “Item 1. Business — Overview of Business and Business — 2013 Developments and Updates.”
We anticipate the above mentioned capital expenditures will be funded primarily with cash on hand and long-term borrowings from OT Finance.
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We believe we have sufficient liquid assets, cash flow from operations and borrowing capacity under the Credit Agreement to meet our financial commitments, debt service obligations and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow. A material decrease in our operating cash flows would likely have an adverse effect on our borrowing capacity.
Financing Activities
2013 Compared to 2012. Net cash flows provided by financing activities for the year ended December 31, 2013 increased by $61.4 million to $131.9 million from $70.5 million for the year ended December 31, 2012. The following were the principal factors resulting in the increase in net cash flows provided by financing activities during the year ended December 31, 2013:
• | During the year ended December 31, 2013, we completed a public offering of 2,600,000 common units at a price to the public of $61.65 per unit. The proceeds from the offering, net of underwriting discounts and other offering expenses, totaled approximately $154.3 million, of which $56.0 million was used to repay the outstanding balance under our Credit Agreement. In connection with the offering, our general partner contributed an additional $3.3 million to us to maintain its 2.0% general partner interest in us. |
• | During the year ended December 31, 2013, we borrowed $50.0 million under the $50.0 million Loan Agreement. In connection with our borrowings under the $50.0 million Loan Agreement, we paid an arrangement fee of $0.2 million to OT Finance. |
• | During the year ended December 31, 2013, we borrowed $100.0 million under the Credit Agreement to finance expansion projects, of which $50.0 million was repaid with proceeds from our $50.0 million Loan Agreement and $56.0 million was repaid with proceeds from a public offering of common units in November 2013. |
• | During the year ended December 31, 2012, we borrowed $125.0 million under the $125.0 million Loan Agreement and $6.0 million under the Credit Agreement to finance expansion projects. In connection with our entry into the $125.0 million Loan Agreement and an amendment of the Credit Agreement, we paid arrangement fees totaling $1.3 million to OT Finance. |
• | During the years ended December 31, 2013 and 2012, we paid $66.9 million ($1.665 per unit) and $56.6 million ($1.425 per unit), respectively, of cash distributions to our limited partners and general partner. |
• | During the years ended December 31, 2013 and 2012, we repaid $2.5 million and $2.5 million of notes payable to an affiliate, respectively. |
2012 Compared to 2011. Net cash flows provided by financing activities for the year ended December 31, 2012 increased by $66.5 million to $70.5 million from $4.0 million for the year ended December 31, 2011. The following were the principal factors resulting in the increase in net cash flows provided by financing activities during the year ended December 31, 2012:
• | During the year ended December 31, 2012, we borrowed $125.0 million under the $125.0 million Loan Agreement and $6.0 million under the Credit Agreement to finance expansion projects. In connection with our entry into the $125.0 million Loan Agreement and an amendment of the Credit Agreement, we paid arrangement fees totaling $1.3 million to OT Finance. |
• | During the year ended December 31, 2012, we paid $56.6 million ($1.425 per unit) of cash distributions to our limited partners and general partner. During the year ended December 31, 2011, we paid $10.6 million ($0.2678 per unit) of cash distributions to our limited partners and general partner as we were only public for a portion of the year. |
• | During the year ended December 31, 2012, we paid $0.2 million of pre-IPO cash distributions to OTA and its affiliates, which had been declared, but not paid, in connection with our IPO in 2011 and was included in accounts payable, affiliates, at December 31, 2011. During the year ended December 31, 2011, we paid $85.5 million of cash distributions to OTA and its affiliates, consisting of: (i) $2.0 million, which had been declared in December 2010 and paid in January 2011, and was included in accounts payable, affiliates, at December 31, 2010, and (ii) $83.5 million, which was paid to OTA in July 2011 in connection with our IPO, $77.0 million of which was paid using proceeds from the public issuance of common units. |
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• | During the year ended December 31, 2011, we received net proceeds of $231.2 million from the issuance of 11,500,000 common units in our IPO, after deducting underwriting discounts and structuring fees. We incurred an additional $3.4 million of costs associated with our IPO, resulting in total net proceeds from our IPO of $227.8 million. |
• | During the years ended December 31, 2012 and 2011, we repaid $2.5 million and $127.5 million of notes payable to an affiliate, respectively. Of the amount repaid in 2011, $119.5 million was repaid in July 2011 with proceeds from our IPO. |
• | During the year ended December 31, 2011, we paid an arrangement fee of $0.3 million in connection with entering into the Credit Agreement. |
Critical Accounting Policies and Estimates
The preparation of consolidated financial statements in conformity with GAAP requires management to select appropriate accounting principles from those available, to apply those principles consistently and to make reasonable estimates and assumptions that affect revenues and associated costs as well as reported amounts of assets and liabilities, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties. We evaluate estimates and assumptions on a regular basis. We base our respective estimates on historical experience and various other assumptions we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from the estimates and assumptions used in preparation of our consolidated financial statements. 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.
Long-Lived Assets
At December 31, 2013 and 2012, the net book value of our property, plant and equipment was $585.8 million and $418.3 million, respectively. Property, plant and equipment is generally recorded at its original acquisition cost, and its carrying value accounted for approximately 80.4% of our consolidated assets at December 31, 2013.
The cost of long-lived assets is generally depreciated on a straight-line basis over the estimated useful lives of the assets ranging from 4 to 40 years. Useful lives are based on historical experience, contract expiration or other reasonable basis, and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. Depreciation and amortization expense was $20.4 million, $15.9 million and $15.7 million for the years ended December 31, 2013, 2012 and 2011, respectively.
In general, long-lived assets, including property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. Such events or changes include, among other factors: operating losses, unused capacity, market value declines, technological developments resulting in obsolescence, changes in demand for products in a market area, changes in competition and competitive practices and changes in governmental regulations or actions. In determining whether the carrying value of our long-lived assets is impaired, we make a number of subjective assumptions including, whether there is an indication of impairment and the extent of any such impairment.
We evaluate the potential impairment of long-lived assets by comparison of estimated undiscounted cash flows for the related asset to the asset’s carrying value. Impairment is indicated when the estimated undiscounted cash flows to be generated by the asset are less than the asset’s carrying value. If the long-lived asset is considered to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset, calculated using a discounted future cash flow analysis.
These future cash flow estimates (both undiscounted and discounted) are based on historical results, adjusted to reflect our best estimate of future market and operating conditions. Uncertainty associated with these cash flow estimates include assumptions regarding demand for the crude oil, refined petroleum products and LPG that we transport, store and distribute, volatility and prices of crude oil and refined petroleum products, the level of domestic oil and gas
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production, discount rates (for discounted cash flows) and potential future sources of cash flows. Such estimates of future undiscounted net cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions.
There were no impairments recorded for the years ended December 31, 2013, 2012 and 2011.
Contingencies
It is common in our industry to be subject to proceedings, lawsuits or other claims related to environmental, labor, product liability or other matters. Among the many uncertainties that impact our estimates of environmental and other contingent liabilities are the potential involvement in lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters, as well as the uncertainties that exist in operating our storage facilities, associated pipeline systems and related facilities. Accruals for contingent liabilities are recorded when our assessment indicates that it is probable that a liability has been incurred and the amount of liability can be reasonably estimated. Such accruals may include estimates and are based on all known facts at the time and our assessment of the ultimate outcome. Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved.
Our insurance does not cover every potential risk associated with operating our storage facilities, pipeline systems and related facilities, including the potential loss of significant revenues. We believe we are adequately insured for liability and property damage to others with respect to our operations. With respect to all of our coverage, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.
At December 31, 2013 and 2012, there were no material accruals for contingencies in the accompanying consolidated financial statements. At December 31, 2013 and 2012, we had not identified any environmental obligations that would require an accrual in our consolidated financial statements. Although the resolution of uncertainties historically has not had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.
Other Considerations
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2013 (in thousands):
Payments Due by Period | |||||||||||||||||||
Total | Less than 1 year | 1-3 years | 3-5 years | More than 5 years | |||||||||||||||
Long-term debt obligations | $ | 190,800 | $ | 2,500 | $ | 5,000 | $ | 5,000 | $ | 178,300 | |||||||||
Interest payments (1) | 82,707 | 10,025 | 19,514 | 18,215 | 34,953 | ||||||||||||||
Purchase commitments (2), (4) | 10,895 | 10,895 | — | — | — | ||||||||||||||
Capital expenditure obligations (3), (4) | 20,115 | 20,115 | — | — | — | ||||||||||||||
Total contractual cash obligations | $ | 304,517 | $ | 43,535 | $ | 24,514 | $ | 23,215 | $ | 213,253 | |||||||||
___________
(1) | Interest payments include amounts due on our currently outstanding notes payable to an affiliate, $125.0 million Loan Agreement and $50.0 million Loan Agreement, and commitment fees due on our Credit Agreement. |
(2) | We have short-term purchase obligations for products and services with third-party suppliers primarily related to construction on our expansion projects. Our estimated future payment obligations are based on the contractual price under each contract for products and services at December 31, 2013. |
(3) | We have short-term payment obligations relating to capital projects we have initiated. These obligations represent unconditional payment obligations we have agreed to pay vendors for services rendered or products |
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purchased and are included in accounts payable and accrued expenses on our consolidated balance sheet as of December 31, 2013.
(4) | Although we are not contractually committed, we have announced approximately $417.0 million of approved expansion projects, of which approximately $230.0 million has not yet been incurred. |
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Related Party Transactions
For more information regarding related party transactions, see “Item 13. Certain Relationships and Related Transactions, and Director Independence” and Notes 3, 8 and 9 in the Notes to Consolidated Financial Statements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. We do not take title to the crude oil, refined petroleum products and LPG we handle and store, and therefore, we do not have direct exposure to risks associated with fluctuating commodity prices. However, we may be indirectly impacted by commodity prices in some instances as a result of the margin sharing component in our terminal service agreement with Enterprise. The throughput revenue we receive on qualifying vessels under this arrangement is determined based on a number of factors, including: (i) the volumes of LPG transported across our docks and (ii) the margin Enterprise receives on those volumes. For more information, see “Item 1A. Risk Factors — A decrease in the volume of LPG transported across our docks, or a decrease in the margin our LPG customer receives subject to our margin sharing arrangement, could negatively impact the throughput revenues we earn.”
In addition, our terminal services agreements with our storage customers are generally indexed to inflation and contain fuel surcharge provisions designed to substantially mitigate our exposure to increases in fuel prices and the cost of other supplies used in our business.
At December 31, 2013, we did not have any variable rate indebtedness. We may use certain derivative instruments to hedge our exposure to variable interest rates in the future, but we do not currently have in place any risk management contracts.
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Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page | |
1. Organization | |
7. Income Taxes | |
8. Debt | |
13. Interest Expense | |
14. Major Customers | |
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors of OTLP GP, LLC, as General Partner of Oiltanking Partners, L.P. and
the Partners of Oiltanking Partners, L.P.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Oiltanking Partners, L.P. (the “Partnership”) as of December 31, 2013 and 2012 and the related consolidated statements of income, comprehensive income, cash flows and partners’ capital for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Oiltanking Partners, L.P. at December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Oiltanking Partners, L.P.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2014, expressed an unqualified opinion thereon.
/s/ BDO USA, LLP
Houston, Texas
February 24, 2014
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OILTANKING PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit amounts)
December 31, | |||||||
2013 | 2012 | ||||||
Assets: | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 17,332 | $ | 7,071 | |||
Receivables: | |||||||
Trade | 18,013 | 12,160 | |||||
Affiliates | 127 | 615 | |||||
Other | 613 | 313 | |||||
Notes receivable, affiliate | 100,000 | 28,000 | |||||
Prepaid expenses and other | 1,502 | 1,290 | |||||
Total current assets | 137,587 | 49,449 | |||||
Property, plant and equipment, net | 585,826 | 418,289 | |||||
Intangible assets | 3,739 | — | |||||
Other assets, net | 1,822 | 1,482 | |||||
Total assets | $ | 728,974 | $ | 469,220 | |||
Liabilities and partners’ capital: | |||||||
Current liabilities: | |||||||
Accounts payable and accrued expenses | $ | 38,104 | $ | 29,399 | |||
Current maturities of long-term debt, affiliate | 2,500 | 2,500 | |||||
Accounts payable, affiliates | 4,264 | 2,049 | |||||
Total current liabilities | 44,868 | 33,948 | |||||
Long-term debt, affiliate, less current maturities | 188,300 | 146,800 | |||||
Deferred revenue | 2,159 | 2,544 | |||||
Total liabilities | 235,327 | 183,292 | |||||
Commitments and contingencies (Note 17) | |||||||
Partners’ capital: | |||||||
Common units (22,049,901 and 19,449,901 units issued and outstanding at December 31, 2013 and 2012, respectively) | 418,435 | 248,176 | |||||
Subordinated units (19,449,901 units issued and outstanding at December 31, 2013 and 2012) | 50,611 | 36,354 | |||||
General partner’s interest | 24,601 | 1,398 | |||||
Total partners’ capital | 493,647 | 285,928 | |||||
Total liabilities and partners’ capital | $ | 728,974 | $ | 469,220 | |||
The accompanying notes are an integral part of these consolidated financial statements.
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OILTANKING PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per unit data)
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Revenues | $ | 210,950 | $ | 135,497 | $ | 117,377 | |||||
Costs and expenses: | |||||||||||
Operating | 43,910 | 36,025 | 31,862 | ||||||||
Selling, general and administrative | 21,765 | 18,856 | 17,985 | ||||||||
Depreciation and amortization | 20,407 | 15,901 | 15,676 | ||||||||
(Gain) loss on disposal of fixed assets | (329 | ) | 13 | 544 | |||||||
Gain on property casualty indemnification | (303 | ) | — | (928 | ) | ||||||
Total costs and expenses | 85,450 | 70,795 | 65,139 | ||||||||
Operating income | 125,500 | 64,702 | 52,238 | ||||||||
Other income (expense): | |||||||||||
Interest expense | (7,393 | ) | (1,654 | ) | (5,438 | ) | |||||
Loss on early extinguishment of debt | — | — | (6,382 | ) | |||||||
Interest income | 30 | 33 | 42 | ||||||||
Other income | 13 | 140 | 431 | ||||||||
Total other expense, net | (7,350 | ) | (1,481 | ) | (11,347 | ) | |||||
Income before income tax (expense) benefit | 118,150 | 63,221 | 40,891 | ||||||||
Income tax (expense) benefit: | |||||||||||
Current | (1,087 | ) | (576 | ) | (5,860 | ) | |||||
Deferred | — | — | 27,366 | ||||||||
Income tax (expense) benefit | (1,087 | ) | (576 | ) | 21,506 | ||||||
Net income | $ | 117,063 | $ | 62,645 | $ | 62,397 | |||||
Allocation of 2011 net income for earnings per unit calculation: | |||||||||||
Net income | $ | 62,397 | |||||||||
Net income prior to initial public offering on July 19, 2011 | (38,591 | ) | |||||||||
Net income subsequent to initial public offering on July 19, 2011 | $ | 23,806 | |||||||||
Allocation of net income to partners: (1) | |||||||||||
Net income allocated to general partner | $ | 22,096 | $ | 1,489 | $ | 476 | |||||
Net income allocated to common unitholders | $ | 48,326 | $ | 30,578 | $ | 11,665 | |||||
Net income allocated to subordinated unitholders | $ | 46,641 | $ | 30,578 | $ | 11,665 | |||||
Earnings per limited partner unit: (1) | |||||||||||
Common unit (basic and diluted) | $ | 2.45 | $ | 1.57 | $ | 0.60 | |||||
Subordinated unit (basic and diluted) | $ | 2.40 | $ | 1.57 | $ | 0.60 | |||||
Weighted average number of limited partner units outstanding: | |||||||||||
Common units (basic and diluted) | 19,735 | 19,450 | 19,450 | ||||||||
Subordinated units (basic and diluted) | 19,450 | 19,450 | 19,450 | ||||||||
_______________________
(1) | Amounts attributable to 2011 are reflective of general and limited partner interest in net income subsequent to the closing of the Partnership’s initial public offering on July 19, 2011. |
The accompanying notes are an integral part of these consolidated financial statements.
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OILTANKING PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Net income | $ | 117,063 | $ | 62,645 | $ | 62,397 | |||||
Postretirement benefit plan adjustment, net of $0, $0 and $33 tax benefit for 2013, 2012 and 2011, respectively | — | — | (62 | ) | |||||||
Comprehensive income | $ | 117,063 | $ | 62,645 | $ | 62,335 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
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OILTANKING PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Cash flows from operating activities: | |||||||||||
Net income | $ | 117,063 | $ | 62,645 | $ | 62,397 | |||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
Depreciation and amortization | 20,407 | 15,901 | 15,676 | ||||||||
Deferred income tax benefit | — | — | (27,366 | ) | |||||||
Postretirement net periodic benefit cost | — | — | 695 | ||||||||
Unrealized gain on investment in mutual funds | — | — | (96 | ) | |||||||
Increase in cash surrender value of life insurance policies | — | — | (42 | ) | |||||||
(Gain) loss on disposal of fixed assets | (329 | ) | 13 | 544 | |||||||
Gain on property casualty indemnification | (303 | ) | — | (928 | ) | ||||||
Amortization of deferred financing costs | 196 | 165 | 66 | ||||||||
Changes in assets and liabilities: | |||||||||||
Trade and other receivables | (5,850 | ) | (6,599 | ) | (579 | ) | |||||
Federal income taxes due (to) from parent | — | (1,210 | ) | 4,174 | |||||||
Prepaid expenses and other assets | (523 | ) | (57 | ) | 665 | ||||||
Accounts receivable/payable, affiliates | 2,703 | 1,682 | 3,754 | ||||||||
Accounts payable and accrued expenses | (248 | ) | 2,847 | (3,070 | ) | ||||||
Deferred compensation | — | — | 453 | ||||||||
Deferred revenue | 1,185 | (133 | ) | 33 | |||||||
Total adjustments from operating activities | 17,238 | 12,609 | (6,021 | ) | |||||||
Net cash provided by operating activities | 134,301 | 75,254 | 56,376 | ||||||||
Cash flows from investing activities: | |||||||||||
Issuance of notes receivable, affiliate | (111,000 | ) | (52,000 | ) | (38,500 | ) | |||||
Collections of notes receivable, affiliate | 39,000 | 39,300 | 20,200 | ||||||||
Payments for purchase of property, plant and equipment | (180,672 | ) | (149,827 | ) | (27,772 | ) | |||||
Proceeds from sale of property, plant and equipment | 440 | — | 14 | ||||||||
Payment for disposal of assets | — | — | (544 | ) | |||||||
Purchase of intangible assets | (3,739 | ) | — | — | |||||||
Proceeds from property casualty indemnification | — | — | 1,298 | ||||||||
Investment in life insurance policies | — | — | (1,378 | ) | |||||||
Proceeds from sale of mutual funds | — | — | 1,378 | ||||||||
Net cash used in investing activities | (255,971 | ) | (162,527 | ) | (45,304 | ) | |||||
Cash flows from financing activities: | |||||||||||
Borrowings under loan agreement, affiliate | 50,000 | 125,000 | — | ||||||||
Borrowings under credit agreement, affiliate | 100,000 | 6,000 | — | ||||||||
Payments under credit agreement, affiliate | (106,000 | ) | — | — | |||||||
Payments under notes payable, affiliate | (2,500 | ) | (2,500 | ) | (127,458 | ) | |||||
Debt issuance costs | (225 | ) | (1,250 | ) | (250 | ) | |||||
Net proceeds from issuance of common units | 154,317 | — | 227,807 | ||||||||
Contribution from general partner | 3,271 | — | 1 | ||||||||
Distributions paid to partners | (66,932 | ) | (56,742 | ) | (96,082 | ) | |||||
Net cash provided by financing activities | 131,931 | 70,508 | 4,018 | ||||||||
Net increase (decrease) in cash and cash equivalents | 10,261 | (16,765 | ) | 15,090 | |||||||
Cash and cash equivalents — Beginning of period | 7,071 | 23,836 | 8,746 | ||||||||
Cash and cash equivalents — End of period | $ | 17,332 | $ | 7,071 | $ | 23,836 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
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OILTANKING PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
Pre-Formation | Post-Formation | ||||||||||||||||||||||||||
Accumulated Other Comprehensive Loss | Limited Partners’ Interests | ||||||||||||||||||||||||||
General Partners’ Interests | Limited Partners’ Interests | General Partner’s Interest | Common Units | Subordinated Units | Total | ||||||||||||||||||||||
Balance — January 1, 2011 | $ | 1,056 | $ | 104,595 | $ | (1,602 | ) | $ | — | $ | — | $ | — | $ | 104,049 | ||||||||||||
Net income attributable to the period from January 1, 2011 through July 18, 2011 | 386 | 38,205 | — | — | — | — | 38,591 | ||||||||||||||||||||
Postretirement benefit plan adjustment, net of $33 tax benefit | — | — | (62 | ) | — | — | — | (62 | ) | ||||||||||||||||||
Contributions from partners | — | 1 | — | — | — | — | 1 | ||||||||||||||||||||
Net distribution of assets and liabilities to partners | (217 | ) | (21,532 | ) | 1,664 | — | — | — | (20,085 | ) | |||||||||||||||||
Cash distribution to partners | (836 | ) | (82,794 | ) | — | — | — | — | (83,630 | ) | |||||||||||||||||
Balance – July 19, 2011, prior to contribution of assets | 389 | 38,475 | — | — | — | — | 38,864 | ||||||||||||||||||||
Contribution of net assets to Oiltanking Partners, L.P. in exchange for common units, subordinated units, incentive distribution rights and a 2% general partner interest | (389 | ) | (38,475 | ) | — | 777 | 11,051 | 27,036 | — | ||||||||||||||||||
Issuance of common units to public, net of offering costs | — | — | — | — | 227,807 | — | 227,807 | ||||||||||||||||||||
Cash distribution to partners | — | — | — | (212 | ) | (5,209 | ) | (5,209 | ) | (10,630 | ) | ||||||||||||||||
Net income attributable to the period from July 19, 2011 through December 31, 2011 | — | — | — | 476 | 11,665 | 11,665 | 23,806 | ||||||||||||||||||||
Balance — December 31, 2011 | — | — | — | 1,041 | 245,314 | 33,492 | 279,847 | ||||||||||||||||||||
Net income | — | — | — | 1,489 | 30,578 | 30,578 | 62,645 | ||||||||||||||||||||
Cash distributions to partners | — | — | — | (1,132 | ) | (27,716 | ) | (27,716 | ) | (56,564 | ) | ||||||||||||||||
Balance — December 31, 2012 | — | — | — | 1,398 | 248,176 | 36,354 | 285,928 | ||||||||||||||||||||
Issuance of common units to public, net of offering costs | — | — | — | — | 154,317 | — | 154,317 | ||||||||||||||||||||
Contribution from general partner | — | — | — | 3,271 | — | — | 3,271 | ||||||||||||||||||||
Net income | — | — | — | 22,096 | 48,326 | 46,641 | 117,063 | ||||||||||||||||||||
Cash distributions to partners | — | — | — | (2,164 | ) | (32,384 | ) | (32,384 | ) | (66,932 | ) | ||||||||||||||||
Balance — December 31, 2013 | $ | — | $ | — | $ | — | $ | 24,601 | $ | 418,435 | $ | 50,611 | $ | 493,647 | |||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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1. ORGANIZATION
Organization
Oiltanking Partners, L.P. (“OILT”) is a Delaware limited partnership formed by Oiltanking Holding Americas, Inc. (“OTA”) on March 14, 2011, to engage in the independent terminaling, storage and transportation of crude oil, refined petroleum products and liquefied petroleum gas (“LPG”). OTA owns and controls OILT’s general partner, OTLP GP, LLC (“general partner”). Through its wholly owned subsidiaries, Oiltanking Houston, L.P. (“OTH”) and Oiltanking Beaumont Partners, L.P. (“OTB”), OILT owns and operates storage and terminaling assets located along the United States Gulf Coast on the Houston Ship Channel and in Beaumont, Texas.
As discussed further below, OILT completed its initial public offering (“IPO”), and OTA and its affiliates contributed all of their equity interests in OTH and OTB to OILT on July 19, 2011. Through July 18, 2011, OTH and OTB were wholly owned subsidiaries of OTA. At December 31, 2013 and 2012, OTA owned OILT’s general partner, 7,949,901 common units and 19,449,901 subordinated units. OTA is a wholly owned subsidiary of Oiltanking GmbH. Oiltanking Finance B.V. (“OT Finance”) is a wholly owned finance company of Oiltanking GmbH that serves as the global financing division for the Oiltanking Group’s terminal holdings, including us, and arranges loans and notes at market rates and terms for approved terminal construction projects.
Oiltanking GmbH and its subsidiaries, other than OILT and its subsidiaries, are collectively referred to herein as the “Oiltanking Group.” As used in this document, the terms “we,” “us,” and “our” and similar terms refer to OILT and its subsidiaries, where applicable, unless the context indicates otherwise.
At December 31, 2013, we had outstanding (i) 22,049,901 common units and 19,449,901 subordinated units representing limited partner interests, (ii) a 2.0% general partner interest and (iii) incentive distribution rights (“IDRs”). OTA and its affiliates hold 66.0% of all of our outstanding common and subordinated units (or a 64.7% limited partner interest), and other security holders hold the remaining 34.0% (or a 33.3% limited partner interest). The limited partners collectively hold a 98.0% limited partner interest in OILT, and the general partner holds a 2.0% general partner interest in OILT.
Offerings
IPO. On July 19, 2011, we completed our IPO of 11,500,000 common units, including 1,500,000 common units issued in connection with the underwriters’ exercise of their over-allotment option, at a price to the public of $21.50 per unit. Our common units are listed on the New York Stock Exchange under the symbol “OILT.”
In exchange for OTA and its affiliates contributing all of their equity interests in OTH and OTB to OILT on July 19, 2011, OILT issued an aggregate of 7,949,901 common units and 19,449,901 subordinated units to OTA and its affiliates and IDRs to its general partner.
The net proceeds from our IPO of approximately $231.2 million, after deducting underwriting discounts and structuring fees, were used to: (i) repay intercompany indebtedness owed to OT Finance in the amount of approximately $119.5 million, (ii) pay OT Finance for approximately $1.0 million of interest due on intercompany indebtedness and reimburse OT Finance for approximately $6.4 million of fees incurred in connection with the repayment of such indebtedness, (iii) make distributions to OTA and its affiliates in the aggregate amount of $77.2 million, (iv) pay other offering expenses of approximately $3.4 million and (v) provide us with working capital of approximately $23.7 million.
In anticipation of our IPO, certain assets and liabilities of OTH and OTB were distributed to OTA. We historically sponsored a non-pension postretirement benefit plan for the employees of all entities owned by OTA and a deferred compensation plan for certain employees (see Notes 11 and 12). On June 1, 2011, the postretirement benefit and deferred compensation plans and obligations were distributed to and assumed by OTA, and certain assets used to fund the deferred compensation plan obligations were distributed to OTA. In addition, effective June 1, 2011, our former employees were transferred to OTA, and OTA became the sponsor of our self-insurance program and 401(k) retirement plan (see Notes 11 and 12). OTH and OTB also made non-cash distributions to OTA, consisting of certain land parcels,
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an office building, other property and equipment, certain accounts receivable and notes receivable, affiliate. OTH and OTB also made cash distributions to OTA. Net deferred tax assets related to these assets and liabilities were also distributed to OTA. See Note 15 for further information regarding the amounts distributed to OTA.
Follow-on Offering. On November 22, 2013, we completed a public offering of 2,600,000 common units at a price to the public of $61.65 per unit. The proceeds from the offering, net of underwriting discounts and other offering expenses, totaled approximately $154.3 million. In connection with the offering, our general partner contributed an additional $3.3 million to us to maintain its 2.0% general partner interest in us. See Note 9 for further information regarding this offering.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We adhere to the following significant accounting policies in the preparation of our consolidated financial statements.
Basis of Presentation and Principles of Consolidation
Because the contribution of OTH and OTB to OILT was a transaction among businesses under common control, the accounts of OTH and OTB have been reflected retroactively in our financial statements at a carryover basis. Therefore, for periods prior to our IPO, the accompanying consolidated financial statements and related notes present the historical accounts of OTH and OTB. The accompanying consolidated financial statements, to the extent they relate to periods prior to our IPO, may not necessarily be indicative of the actual results of operations that might have occurred if OILT had existed as a separate entity during those periods. In addition, the effects of our IPO, certain related asset and liability transfers, cash distributions and debt extinguishment transactions that occurred in June and July 2011 are reflected in the historical consolidated financial statements on the dates the transactions occurred.
The consolidated financial statements and the accompanying notes are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and the rules of the U.S. Securities and Exchange Commission (“SEC”). All significant intercompany transactions and balances have been eliminated in consolidation.
Asset Retirement Obligations
We regularly assess our legal obligations with respect to estimated retirements of certain of our long-lived assets to determine if an asset retirement obligation (“ARO”) exists. GAAP requires the fair value of a liability related to the retirement of long-lived assets be recorded at the time a legal obligation is incurred, if the liability can be reasonably estimated. When the liability is initially recorded, the carrying amount of the related asset is increased by the amount of the liability. Over time, the liability is accreted to its future value, with the accretion recorded to expense. GAAP further requires where there is an obligation to perform an asset retirement activity, even though uncertainties exist about the timing or method of settlement, an entity is required to recognize a liability for the fair value of a conditional ARO if the fair value of the liability can be determined.
Our assets generally consist of storage tanks and underground pipelines and related facilities along rights-of-way. Our rights-of-way agreements typically do not require the dismantling, removal and reclamation of the right-of-way upon permanent removal of the pipelines and related facilities from service. Additionally, we are unable to predict when, or if, our pipelines, storage tanks and related facilities would become completely obsolete and require decommissioning. Accordingly, we have not recorded a liability or corresponding asset as both the amounts and timing of such potential future costs are indeterminable.
Business Segments
We report in one business segment. We derive our revenues from two operating segments — OTH and OTB. The two operating segments have been aggregated into one reportable segment because they have similar long-term economic characteristics, types and classes of customers and provide similar services. The aggregation of operating segments into one reportable segment requires management to evaluate whether there are similar expected long-term
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economic characteristics for each operating segment, and is an area of significant judgment. If the expected long-term economic characteristics of our operating segments were to become dissimilar, then we could be required to re-evaluate the number of reportable segments.
Capitalization of Interest
Interest on borrowed funds is capitalized on projects during construction based on the approximate average interest rate of our debt. Interest capitalized for the years ended December 31, 2013, 2012 and 2011 was $2.1 million, $1.7 million and $0.6 million, respectively.
Cash and Cash Equivalents
Cash equivalents represent all highly liquid investments with original maturities of three months or less. The carrying value of cash equivalents approximates fair value because of the short-term nature of these investments. At December 31, 2013 and 2012, cash and cash equivalents was comprised of cash held in banks.
Our consolidated statements of cash flows are prepared using the indirect method. The indirect method derives net cash flows from operating activities by adjusting net income to remove (i) the effects of all deferrals of past operating cash receipts and payments, such as changes during the period in deferred income and similar transactions, (ii) the effects of all accruals of expected future operating cash receipts and cash payments, such as changes during the period in receivables and payables, (iii) the effects of all items classified as investing or financing cash flows, such as gains or losses on sale of property, plant and equipment or extinguishment of debt, and (iv) other non-cash amounts such as depreciation and amortization.
Concentrations of Credit Risk
Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash, cash equivalents, trade receivables and other receivables. Cash and cash equivalents are held on deposit with major banks. We maintain our cash and cash equivalents at financial institutions for which the combined account balances in individual institutions may exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is a credit risk related to amounts on deposits in excess of FDIC coverage. We believe the financial institutions holding these amounts are financially sound and, accordingly, minimal credit risk exists with respect to these assets.
We extend credit to our customers primarily in the petroleum and related service industries but do not consider there to be any concentration of credit risk with any single customer. See Note 14 for additional information.
Contingencies
Certain conditions may exist as of the date our consolidated financial statements are issued that may result in a loss to us, but which will only be resolved when one or more future events occurs or fails to occur. Our management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings pending against us or unasserted claims that may result in proceedings, our management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
If the assessment of a contingency indicates it is probable a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our consolidated financial statements. If the assessment indicates a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.
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Debt Issuance Costs
Costs incurred to issue our debt instruments are capitalized and amortized over the life of the associated debt instrument using the effective interest method. If the debt instrument is retired before its scheduled maturity date, any remaining issuance costs associated with that debt instrument are expensed in the same period.
Deferred Compensation
We established and maintained an unfunded, non-qualified deferred compensation plan for a select group of management or highly compensated employees. The purpose of the deferred compensation plan was to permit designated employees to accumulate additional retirement income through a non-qualified deferred compensation plan that enabled them to defer compensation to which they will become entitled in the future. On June 1, 2011, the deferred compensation plan and obligations were distributed to and assumed by OTA, and certain assets to be used to fund the deferred compensation plan obligations were distributed to OTA.
Earnings per Limited Partner Unit
Basic and diluted net income per unit is determined by dividing net income, after deducting the general partner’s interest, allocated to each class of limited partner units, by the weighted average number of limited partner units for such class outstanding during the period. We allocate net income to our limited partners and our general partner in accordance with our partnership agreement. Under the two-class method, because our partnership agreement does not limit distributions to our general partner with respect to IDRs to available cash, we allocate undistributed earnings to our general partner utilizing the distribution waterfall for available cash specified in our partnership agreement. Diluted earnings per limited partner unit reflects, where applicable, the potential dilution that could occur if securities or other agreements to issue additional units of a limited partner class, such as phantom unit awards, were exercised, settled or converted into such units (see Note 10). We currently do not have any of these types of awards outstanding.
Environmental Expenditures
Environmental costs are expensed if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration, environmental remediation, cleanup or other obligations are either known or considered probable and can be reasonably estimated. At December 31, 2013 and 2012, we had not identified any environmental obligations that would require an accrual in our consolidated financial statements.
Estimates
The preparation of our consolidated financial statements in conformity with GAAP requires management to use estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates and judgments on historical experience and on various other assumptions and information we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.
Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value measurements are derived using inputs and assumptions market participants would use in pricing an asset or liability, including assumptions about risk. GAAP establishes a valuation hierarchy for disclosure of the inputs used to measure fair value. This three-tier hierarchy classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs
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used to estimate such fair values. The classification within the hierarchy of a financial asset or liability is determined based on the lowest level input that is significant to the fair value measurement. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3).
Notes receivable, affiliate are reported in the consolidated balance sheets at amounts which approximate fair value due to the relatively short period to maturity of these financial instruments (Level 2). The carrying values of our fixed-rate debt obligations approximate fair value based upon borrowing rates currently available to us for loans with similar terms (Level 2). The carrying values of our variable-rate debt obligations approximate their fair values because the associated interest rates are market-based. See Note 8 for further details of our fixed-rate and variable-rate debt obligations.
We believe our valuation methods are appropriate and consistent with the values that would be determined by other market participants. However, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date.
Impairment Assessment of Long-Lived Assets
We periodically evaluate whether events or circumstances have occurred that indicate the estimated remaining useful life of long-lived assets, including property and equipment, may warrant revision or that the carrying value of these assets may be impaired. We evaluate the potential impairment of long-lived assets based on undiscounted cash flow expectations for the related asset relative to its carrying value. These future estimates are based on historical results, adjusted to reflect our best estimates of future market and operating conditions. Actual results may vary materially from our estimates, and accordingly may cause a full impairment of the long-lived assets. If a long-lived asset is considered to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset exceeds its fair value, calculated using a discounted future cash flows analysis. There were no impairments recorded for the years ended December 31, 2013, 2012 and 2011.
Income Taxes
For periods prior to our IPO, no provision for U.S. federal income taxes has been made in our consolidated financial statements related to the operations of OTB, as OTB had been treated as a partnership not subject to federal income tax and the tax effects of OTB’s operations were included in the consolidated federal income tax return of OTA. OTH also was included in the consolidated federal income tax return of OTA, but OTH historically had elected to be taxed as a corporation, and income tax expense included provisions calculated as if OTH had filed a separate tax return utilizing a statutory rate of 35%. Deferred income taxes resulted from temporary differences between the income tax basis of the assets and liabilities and the amounts reported in OTH’s financial statements.
In July 2011, OTH elected to be treated as a disregarded entity for U.S. federal income tax purposes. Due to the change in tax status of OTH, we recognized a non-recurring income tax benefit of $27.1 million related to the elimination of the deferred tax account balances, which is included in our consolidated statement of income for the year ended December 31, 2011.
The financial statement benefit of an uncertain tax position is recognized only after considering the probability a tax authority would sustain the position in an examination. For tax positions meeting a “more-likely-than-not” threshold, the amount recognized in the financial statements is the benefit expected to be realized upon settlement with the tax authority. For tax positions not meeting the threshold, no financial statement benefit is recognized. We recognize interest and other charges relating to unrecognized tax benefits as additional tax expense. We have not recognized any liabilities for uncertain tax positions in our consolidated balance sheets.
Effective January 1, 2007, the Texas margin tax applies to legal entities conducting business in Texas, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The margin tax is based on our Texas-sourced taxable margin. The tax is calculated by applying a tax rate to a base that considers both revenues and expenses and therefore has the characteristics of an income tax.
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Intangible Assets
In June 2013, we acquired emission allowances for $3.7 million from a third party, primarily for use in connection with the expansion of storage capacity at our Houston area facilities. These emission allowances are being accounted for as intangible assets with a finite life and will be amortized to operating expenses based on units of production once the assets that will utilize the emission allowances are placed into service, which is expected to begin in 2015.
Investments
We held mutual funds and life insurance policies with cash surrender values in conjunction with our deferred compensation plan. The investments were carried at fair value, with unrealized gains and losses reported as other income (expense). On June 1, 2011, the deferred compensation plan and obligations were distributed to and assumed by OTA, and certain assets to be used to fund the deferred compensation plan obligations were distributed to OTA.
Net Income Allocation
We allocate net income to our partners for two primary purposes: (i) under the two-class method for purposes of computing earnings per limited partner unit and (ii) in accordance with the partnership agreement for purposes of maintaining our limited partners’ and general partner’s capital accounts.
We allocate net income to our limited partners and our general partner in accordance with our partnership agreement. Under the two-class method, because our partnership agreement does not limit distributions to our general partner with respect to IDRs to available cash, we allocate undistributed earnings to our general partner utilizing the distribution waterfall for available cash specified in our partnership agreement. Cash payments made to our general partner and limited partners are determined in relation to actual distributions declared and are not based on the net income allocations used in the calculation of earnings per unit.
Postretirement Benefit Plan Obligations
Prior to our IPO, we sponsored an unfunded multi-employer postretirement healthcare benefit plan, covering employees and retirees of OTH, OTB and other subsidiaries of OTA. Because OTH was the primary obligor, the postretirement benefit liabilities represented the present value of all of the benefit obligations of the plan. Postretirement benefit costs were developed from actuarial valuations. Actuarial assumptions were established to anticipate future events and were used in calculating the expense and liabilities related to this plan. These factors included assumptions management made regarding interest rates, rates of increase in health care costs and employee turnover rates, among others. Management reviewed and updated these assumptions on an annual basis. The actuarial assumptions used could have differed from actual results due to changing market rates or other factors. These differences could have impacted the amount of postretirement benefit expense recorded. Effective June 1, 2011, OTA became the sponsor of our postretirement healthcare benefit plan, and our obligations under this plan along with our former employees were transferred to OTA.
Property, Plant and Equipment
We record property, plant and equipment at its original acquisition cost. Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value less subsequent accumulated depreciation, if impaired. We capitalize all direct and indirect construction costs and related interest. Indirect construction costs include general engineering, taxes and the cost of funds used during construction. Costs, including complete asset replacements and enhancements or upgrades that increase the original efficiency, productivity or capacity of property, plant and equipment, are also capitalized. The costs of repairs, minor replacements and maintenance projects which do not increase the original efficiency, productivity or capacity of property, plant and equipment, are expensed as incurred.
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Property, plant and equipment are depreciated using the straight-line method, over the estimated useful life of each asset as follows:
Estimated Life in Years | |
Production and terminal facilities | 4 to 40 |
Rights of way | 10 to 15 |
We assign asset lives based on reasonable estimates when an asset is placed into service. Subsequent events could cause us to change our estimates, which would impact the future calculation of depreciation expense.
Revenue Recognition
We provide integrated storage, throughput and ancillary services for third-party companies engaged in the production, distribution and marketing of crude oil, refined petroleum products and LPG. We generate revenues through the provision of services to our customers under a combination of multi-year and month-to-month agreements. Certain agreements contain “take-or-pay” provisions whereby we are entitled to a minimum throughput or storage fee. We recognize revenues when the service is provided, the crude oil, refined petroleum products and LPG are received at or delivered from our terminals or when the customer’s ability to make up the minimum volume has expired, in accordance with the terms of the contracts.
We recognize revenues in accordance with applicable accounting standards. Our assessment of each of the four revenue recognition criteria as they relate to our revenue producing activities is as follows:
• | Persuasive Evidence of an Arrangement Exists. Our customary practices are to enter into a written contract, executed by both the customer and us. |
• | Service is Provided. We consider services provided when the crude oil, refined petroleum products and LPG are shipped through, delivered by or stored in our pipelines, terminals and storage facilities, as applicable. |
• | Fixed or Determinable Fee. We negotiate the fees for our services at the outset of our fee-based agreements. Under certain contracts, the fees generally are due in advance on the first of the month. For other agreements, the amount of revenue is determinable after services are provided and volumes handled can be measured. |
• | Collection is Deemed Probable. Collectability is evaluated on a customer-by-customer basis. We conduct a credit review for all customers at the inception of a new agreement to determine the creditworthiness of potential and existing customers. Collection is deemed probable if we expect the customer will be able to pay amounts under the agreement as payments become due. If we determine collection is not probable, revenues are deferred and recognized upon cash collection. |
We collect taxes on certain revenue transactions to be remitted to governmental authorities, which may include sales, use, value added and some excise taxes. These taxes are not included in revenue.
Trade Receivables and Allowance for Doubtful Accounts
Trade accounts receivable are customer obligations due under agreed-upon trade terms. We regularly perform credit evaluations of our customers and generally do not require collateral. We regularly review trade accounts receivable to determine if any receivables could potentially be uncollectible, and if so, include a determined amount in the allowance for doubtful accounts. Based on the information available, we believe no allowance for doubtful accounts was needed at December 31, 2013 and 2012. However, actual write-offs may occur.
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Unit-Based Compensation
We have a long-term incentive plan, the Oiltanking Partners, L.P. Long-Term Incentive Plan (the “LTIP”), for employees, consultants and directors of the general partner and those of its affiliates, including Oiltanking North America, LLC (“OTNA”), a subsidiary of OTA, who perform services for us. The LTIP provides for the grant of restricted units, unit options, phantom units, unit payments, unit appreciation rights, other equity-based awards, distribution equivalent rights and performance awards. The LTIP limits the number of common units that may be delivered pursuant to awards under the plan to 3,889,980 units. As of December 31, 2013, no awards have been granted under the LTIP.
3. RELATED PARTY TRANSACTIONS
We have engaged in certain transactions with other OTA subsidiaries, as well as other companies related to us by common ownership. Ongoing transactions include our provision of storage and ancillary services to these affiliates. Prior to July 19, 2011, we also provided certain centralized administrative services including, among others, rental of administrative and operations office facilities, human resources, information technology, engineering, environmental and regulatory, treasury and certain financial services. Amounts charged for storage and ancillary services are classified as revenues. Amounts charged for the other administrative services discussed above are classified as a reduction of selling, general and administrative expense. Effective July 19, 2011, OTA began providing these administrative services to us and other OTA affiliates.
Total revenues for related party services were as follows for the periods indicated (in thousands):
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Storage and ancillary service fees | $ | 3,317 | $ | 3,212 | $ | 3,142 | |||||
Other revenues | — | 13 | 1,565 | ||||||||
Total related party revenues | $ | 3,317 | $ | 3,225 | $ | 4,707 | |||||
Prior to our IPO, we paid fees directly to Oiltanking GmbH for various general and administrative services, which included, among others, risk management, environmental compliance, legal consulting, information technology, engineering, centralized cash management and certain treasury and financial services. Oiltanking GmbH allocated these costs to us using several factors, such as our tank capacity and total volumes handled. In management’s estimation, the costs charged for these services approximated the amounts that would have been incurred for similar services purchased from third parties or provided by our own employees. Subsequent to our IPO, these services are provided pursuant to the Services Agreement discussed below.
Effective June 1, 2011, in anticipation of our IPO, all of our former employees were transferred to OTA. Effective July 19, 2011, certain operating and selling, general and administrative services necessary to operate our business are provided by OTA pursuant to the Services Agreement. Charges for these services are included in operating and selling, general and administrative expenses in the table below.
We also paid annual maintenance and technical support costs for proprietary software owned by Oiltanking GmbH, which we use in performing terminaling services for our customers. Each terminal location was allocated a portion of the global Oiltanking GmbH maintenance costs based on the number of users located at each facility. In management’s estimation, the costs incurred approximate the amounts that would have been incurred for similar third-party software programs for terminaling operations. Subsequent to our IPO, these services are provided pursuant to the Services Agreement.
During the years ended December 31, 2013, 2012 and 2011, we capitalized $5.5 million, $4.3 million and $0.9 million, respectively, of related party engineering services into construction in progress.
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At December 31, 2013 and 2012, total related party accounts receivable were $0.1 million and $0.6 million, respectively. Total related party accounts payable were $4.3 million and $2.0 million at December 31, 2013 and 2012, respectively. Additionally, we had $6.7 million and $0.1 million within accounts payable and accrued expenses at December 31, 2013 and 2012, respectively, associated with related party administrative fees (see Note 5).
Long-term debt payable to OT Finance, including both current and long-term portions, at December 31, 2013 and 2012, was $190.8 million and $149.3 million, respectively. In July 2011, we repaid approximately $119.5 million of the outstanding notes payable, affiliate, with proceeds from our IPO. We also reimbursed OT Finance for approximately $6.4 million of fees incurred in connection with the repayment of such indebtedness. See Note 8 for further details of our debt and credit agreements.
At December 31, 2013 and 2012, total interest and commitment fees payable to OT Finance under term loans and credit financing arrangements of $0.6 million and $0.6 million, respectively, were included in accounts payable and accrued expenses (see Note 5).
From time to time, we invest cash with OT Finance in short-term notes receivable at then-prevailing market rates. At December 31, 2013 and 2012, we had short-term notes receivable of $100.0 million and $28.0 million, respectively, from OT Finance, bearing weighted-average interest rates of 0.23% and 0.15%, respectively.
The following table summarizes related party operating expenses, selling, general and administrative expenses, interest expense and interest income reflected in the consolidated statements of income for the periods indicated (in thousands):
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Operating | $ | 15,129 | $ | 12,997 | $ | 4,795 | |||||
Selling, general and administrative (1) | 17,908 | 15,952 | 10,622 | ||||||||
Interest expense (net of amounts capitalized) | 7,368 | 1,628 | 5,413 | ||||||||
Loss on early extinguishment of debt | — | — | 6,382 | ||||||||
Interest income | 30 | 33 | 42 | ||||||||
____________
(1) | Amounts represent selling, general and administrative expenses incurred under the Services Agreement (as defined below) beginning July 19, 2011. For the period from July 19, 2011 through December 31, 2011, we incurred $6.6 million of selling, general and administrative expenses under the Services Agreement. Selling, general and administrative expenses for the years ended December 31, 2013, 2012 and 2011 also include $1.0 million, $1.1 million and $0.3 million, respectively, of costs from OTA related to ongoing maintenance for an invoicing and inventory computer system that are reimbursable under the Services Agreement but not included in the annual fixed fee set forth in the agreement. |
See Notes 1 and 15 for a discussion of asset and liability transfers made in connection with our IPO.
Transactions with a Certain Director
One of the directors of our general partner, David L. Griffis, is employed by and a shareholder of the law firm of Crain, Caton & James, P.C., a firm that provides legal counsel to us, as well as to OTA and certain of its other affiliates. Fees for legal services paid to Crain, Caton & James, P.C. for services provided to us totaled $1.2 million, $1.1 million and $0.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Agreements with Affiliates
Services Agreement. On July 19, 2011, in connection with our IPO, we entered into a services agreement (the “Services Agreement”) with our general partner and OTNA, a subsidiary of OTA, and subsequently amended the Services Agreement in December 2011, pursuant to which OTNA agreed to provide us certain specified selling, general
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and administrative services necessary to manage our business for an annual fixed fee, payable in equal monthly installments. We also agreed to reimburse OTNA for all operating expenses and all expenses it incurs as a result of our becoming a publicly traded partnership, including all operating expenses it incurs with respect to insurance coverage for our business, with such reimbursement obligations not subject to any cap.
The initial term of the Services Agreement is ten years, and it will automatically renew for additional twelve-month periods following the expiration of the initial term unless and until either we or OTNA provide 180 days written notice of intent to terminate the agreement. During the initial term or any renewal term, the annual fixed fee related to selling, general and administrative expenses will be adjusted as necessary each year to account for inflation as measured by the consumer price index. In addition, with the approval of the Conflicts Committee of the board of directors of our general partner, the fee may be adjusted to account for growth in our business or asset base. In January 2013, the annual fixed fee was increased from $14.9 million to $15.1 million as a result of an increase in the consumer price index.
In August 2013, the Conflicts Committee of the board of directors of our general partner approved a requested increase to the fixed fee charged to us under the Services Agreement to $18.8 million on an annualized basis to reflect higher selling, general and administrative expenses associated with expansion projects placed in service in 2013. These expansion projects include the Houston crude oil storage and pipeline expansion, the first phase of our Appelt storage facility and related pipeline connections, and incremental refined petroleum products storage at our Beaumont terminal. The fee increase was effective as of July 1, 2013.
Omnibus Agreement. On July 19, 2011, in connection with the closing of our IPO, we entered into an omnibus agreement (the “Omnibus Agreement”) with our general partner and OTA, pursuant to which OTA agreed to provide us with a license to use the name “Oiltanking” and related marks in connection with our business at no cost to us.
The Omnibus Agreement also provides for certain indemnification obligations between us and OTA with respect to the assets which were contributed to us by OTA in connection with the closing of our IPO. OTA’s indemnification obligations to us include the following: (i) for a period of three years after the closing of our IPO, OTA will indemnify us for environmental losses arising out of any event or circumstance associated with the operation of our assets prior to the closing of our IPO of up to $15.0 million in the aggregate, provided that OTA will only be liable to provide indemnification for losses to the extent that the aggregate dollar amount of losses suffered by us exceeds $0.5 million in any calendar year; (ii) until 60 days after the applicable statute of limitations, OTA will indemnify us for any additional federal, state and local income tax liabilities attributable to the ownership and operation of our assets and the assets of our subsidiaries prior to the closing of our IPO; (iii) for a period of three years after the closing of our IPO, OTA will indemnify us for any losses resulting from the failure to have all necessary consents and governmental permits necessary for us to operate our assets in substantially the same manner in which they were used and operated immediately prior to the closing of our IPO; and (iv) for a period of three years after the closing of our IPO, OTA will indemnify us for any losses resulting from our failure to have valid and indefeasible easement rights, rights-of-way, leasehold and/or fee ownership interests in the lands where our assets are located if such failure prevents us from using or operating our assets in substantially the same manner as they were operated immediately prior to the closing of our IPO. The Omnibus Agreement will generally remain in effect so long as OTA controls our general partner, or unless mutually terminated by the parties.
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4. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consist of the following at the dates indicated (in thousands):
December 31, | |||||||
2013 | 2012 | ||||||
Land | $ | 23,436 | $ | 23,340 | |||
Production and terminal facilities | 661,184 | 460,239 | |||||
Construction in progress | 120,761 | 136,876 | |||||
Total property, plant and equipment | 805,381 | 620,455 | |||||
Less: accumulated depreciation | (219,555 | ) | (202,166 | ) | |||
Total property, plant and equipment, net | $ | 585,826 | $ | 418,289 | |||
Depreciation and amortization expense was $20.4 million, $15.9 million and $15.7 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Interest costs capitalized as part of the costs of construction in progress were $2.1 million, $1.7 million and $0.6 million during the years ended December 31, 2013, 2012 and 2011, respectively.
During the year ended December 31, 2013, we recognized a gain of $0.3 million from proceeds received for an insurance claim related to damages sustained during a hurricane in 2008. During the year ended December 31, 2011, we recognized gains of $0.9 million, of which $0.7 million was a gain from proceeds received for an insurance claim related to damages sustained during a hurricane in 2008 and $0.2 million was a gain from proceeds received for an insurance claim resulting from property damages which occurred in 2008 to a dock at our Beaumont terminal.
During the year ended December 31, 2013, we recognized a gain of $0.3 million on the disposal of certain terminal assets that were dismantled. During the years ended December 31, 2012 and 2011, we recognized losses of less than $0.1 million and approximately $0.5 million, respectively, on the disposal of certain terminal assets that were dismantled.
5. ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses consist of the following at the dates indicated (in thousands):
December 31, | |||||||
2013 | 2012 | ||||||
Accounts payable, trade | $ | 3,820 | $ | 7,891 | |||
Accrued capital expenditures | 15,120 | 12,732 | |||||
Accrued property taxes | 6,952 | 4,987 | |||||
Accrued sales and other taxes | 421 | 207 | |||||
Related party interest and commitment fees payable | 557 | 611 | |||||
Related party administrative fees payable | 6,703 | 60 | |||||
Deferred revenue | 2,609 | 1,039 | |||||
Other | 1,922 | 1,872 | |||||
Total accounts payable and accrued expenses | $ | 38,104 | $ | 29,399 | |||
6. DEFERRED REVENUE
During 2007, we entered into a modification of a lease, in which we, as a lessor, received a one-time upfront rental payment of $2.5 million, which is being amortized on a straight-line basis over the term of the lease of approximately sixteen years. At December 31, 2013 and 2012, deferred revenue related to this upfront rental payment was $1.4 million
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and $1.6 million, respectively, of which $0.2 million at each date was current and included in accounts payable and accrued expenses.
During 2010, we entered into a modification of a revenue agreement with a customer and received a one-time payment of $2.0 million, which is being amortized on a straight-line basis over the remaining term of the agreement of approximately nine years. At December 31, 2013 and 2012, deferred revenue related to this one-time payment was $1.1 million and $1.4 million, respectively, of which $0.2 million at each date was current and included in accounts payable and accrued expenses.
At December 31, 2011, we had $0.4 million of current deferred revenue related to an advance payment received from a customer, and such amount was included in accounts payable and accrued expenses. During the first quarter of 2012, we completed the construction of pipeline-related assets for the customer, and recognized the deferred revenue of $0.4 million related to the project.
At December 31, 2013 and 2012, we had $2.2 million and $0.6 million, respectively, of current deferred revenue related to a customer throughput and deficiency agreement.
7. INCOME TAXES
For periods prior to our IPO, no provision for U.S. federal income taxes has been made in our consolidated financial statements related to the operations of OTB, as OTB had been treated as a partnership not subject to federal income tax and the tax effects of OTB’s operations were included in the consolidated federal income tax return of OTA. OTH also was included in the consolidated federal income tax return of OTA, but OTH historically had elected to be taxed as a corporation, and income tax expense included provisions calculated as if OTH had filed a separate tax return utilizing a statutory rate of 35%. Deferred income taxes resulted from temporary differences between the income tax basis of the assets and liabilities and the amounts reported in OTH’s financial statements.
In July 2011, OTH elected to be treated as a disregarded entity for U.S. federal income tax purposes. Upon the change in tax status of OTH, we recognized a non-recurring income tax benefit of $27.1 million related to the elimination of all of our deferred tax accounts, which is included in our consolidated statements of income for the year ended December 31, 2011.
Due to our status as a partnership, we and our subsidiaries, including OTH and OTB, are not subject to U.S. federal or state income taxes, with the exception of the Texas margin tax.
Total income tax expense differed from the amounts computed by applying the tax rate to income before income tax expense as a result of the following for the periods indicated (in thousands):
Year Ended December 31, | |||
2011 | |||
Income before income tax benefit | $ | 40,891 | |
U.S. federal corporate statutory rate | 35 | % | |
Expected income tax expense | (14,312 | ) | |
OILT, OTB and OTH income not subject to income tax | 8,974 | ||
Elimination of deferred tax account balances | 27,052 | ||
Texas margin tax, net of federal income tax benefit | (208 | ) | |
Total income tax benefit | $ | 21,506 | |
During the years ended December 31, 2013 and 2012, we recorded $1.1 million and $0.6 million, respectively, of income tax expense related to the Texas margin tax.
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Our policy is to classify any interest and penalties associated with income taxes as income tax expense. During the years ended December 31, 2013, 2012 and 2011, we did not recognize any amounts in respect of potential interest and penalties associated with income taxes.
Our 2009 through 2013 tax years are potentially subject to examination by the federal and state taxing authorities because the statutes of limitations for those years have not closed.
8. DEBT
Long-term debt, affiliate, consists of the following at the dates indicated (in thousands):
December 31, | |||||||
2013 | 2012 | ||||||
6.78% Note due 2019 – OTH | $ | 5,400 | $ | 6,300 | |||
7.45% Note due 2019 – OTB | 4,800 | 5,600 | |||||
7.02% Note due 2020 – OTB | 5,600 | 6,400 | |||||
4.55% OTH $125.0 million Loan Agreement, due 2022 | 125,000 | 125,000 | |||||
5.435% OTH $50.0 million Loan Agreement, due 2023 | 50,000 | — | |||||
OILT Credit Agreement, due 2017 | — | 6,000 | |||||
Total debt | 190,800 | 149,300 | |||||
Less current portion | (2,500 | ) | (2,500 | ) | |||
Total long-term debt, affiliate | $ | 188,300 | $ | 146,800 | |||
The following table presents the scheduled maturities of principal amounts of our debt obligations for the next five years and in total thereafter (in thousands):
Years Ending | |||
December 31, | |||
2014 | $ | 2,500 | |
2015 | 2,500 | ||
2016 | 2,500 | ||
2017 | 2,500 | ||
2018 | 2,500 | ||
Thereafter | 178,300 | ||
Total | $ | 190,800 | |
In connection with our IPO, we repaid intercompany indebtedness owed to OT Finance in the amount of approximately $119.5 million, reimbursed OT Finance for approximately $6.4 million of fees incurred in connection with the repayment of such indebtedness, and paid $1.0 million of interest. The $6.4 million payment is reflected as a loss on the early extinguishment of debt in our consolidated statement of income for the year ended December 31, 2011.
At December 31, 2013, under the most restrictive terms of our covenants, partners’ capital of $316.2 million was available for distribution.
OTH and OTB Notes
At December 31, 2013, we have three outstanding notes with OT Finance. Two of the outstanding notes contain loan covenants requiring OTB to maintain certain debt, leverage and equity ratios and prohibit OTB from pledging its assets to third parties or incurring any indebtedness other than from OT Finance without its consent. At December 31,
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2013 and 2012, no assets had been pledged to third parties. The loan covenants in these agreements require OTB to maintain certain Financial Parameters (as such term is defined in the note agreements), including: (i) a ratio of Stockholders’ Equity to non-current assets of 30% or greater, (ii) a ratio of EBITDA to Total Debt Service of 1.2 or greater and (iii) a ratio of Net Financial Indebtedness to EBITDA of 3.75 or less (as such terms are defined in the note agreements). At December 31, 2013, OTB’s ratio of Stockholders’ Equity to non-current assets, the ratio of EBITDA to Total Debt Service and the ratio of Net Financial Indebtedness to EBITDA (as such terms are defined in the note agreements) were 97.1%, 9.0 and 0.12, respectively. At December 31, 2013, OTB was in compliance with all covenants under the respective note agreements.
OTH Loan Agreements
On May 16, 2012, OTH entered into a ten-year $125.0 million unsecured loan agreement with OT Finance (the “$125.0 million Loan Agreement”) for the purpose of financing the purchase of property, plant and equipment, through which borrowings were available through December 15, 2012, with a maturity date of December 15, 2022. During its availability period, interest on borrowings outstanding under this loan agreement was calculated on the basis of an annual interest rate determined by OT Finance, which represented OT Finance’s cost of funds, plus a margin of 2.70% per annum. In October 2012, OTH agreed to fix the interest rate applicable to borrowings under this loan agreement after the availability period at 4.55% per annum (calculated as the USD Swap Rate for ten years as of the date of determination of 1.85% plus a margin of 2.70%). A commitment fee of 1.00% per annum was calculated on the undrawn amount of the $125.0 million Loan Agreement and paid at the end of each month during the availability period. Interest that accrued during the availability period was payable at the end of the availability period. After the availability period, interest payments are payable semi-annually, beginning in December 2012. OTH paid an arrangement fee in June 2012 of $0.8 million to OT Finance, the expense of which was deferred and is being amortized over the term of the loan agreement. At December 31, 2013 and 2012, OTH had $125.0 million of outstanding borrowings under this loan agreement at a fixed interest rate of 4.55% per annum.
On June 26, 2013, OTH entered into a ten-year $50.0 million unsecured loan agreement with OT Finance (the “$50.0 million Loan Agreement”) for the purpose of financing the purchase of property, plant and equipment, through which borrowings were available through August 31, 2013, with a maturity date of June 30, 2023. During its availability period, interest on borrowings outstanding under this loan agreement was calculated on the basis of an annual interest rate determined by OT Finance, which represented OT Finance’s cost of funds, plus a margin of 2.60% per annum. After the end of the availability period and through the maturity date, interest is calculated on the basis of the USD swap rate for ten years, plus a margin of 2.60% per annum. Interest that accrued during the availability period was payable at the end of the availability period. After the availability period, interest payments are payable semi-annually, beginning in December 2013. OTH paid an arrangement fee in July 2013 of $0.2 million to OT Finance, the expense of which was deferred and is being amortized over the term of the loan agreement. In July 2013, OTH borrowed $50.0 million under this loan agreement, and the proceeds were used to repay outstanding balances under the revolving line of credit agreement (discussed below). In July 2013, OTH also agreed to fix the interest rate applicable to borrowings under this loan agreement after the availability period at 5.435% per annum (calculated as the USD swap rate for ten years as of the date of determination of 2.835% plus a margin of 2.60%). At December 31, 2013, OTH had $50.0 million of outstanding borrowings under this loan agreement at a fixed interest rate of 5.435% per annum.
The loan agreements contain covenants restricting the ability of OTH to take certain actions without the consent of OT Finance, including incurring additional indebtedness, pledging its assets or amending its organizational documents. The loan agreements contain borrowing conditions and events of default, including events of default triggered by (i) OTH failing to satisfy the Financial Parameters and other covenants described in this paragraph after more than 30 days’ notice, (ii) OTH failing to repay borrowings under the loan agreements when they become due, and (iii) OTH ceasing to be controlled by Oiltanking GmbH. The loan agreements require OTH to maintain certain Financial Parameters (as such term is defined in the loan agreements), including: (i) a ratio of Stockholders’ Equity to non-current assets of 30% or greater, (ii) a ratio of EBITDA to Total Debt Service of 1.2 or greater, and (iii) a ratio of Net Financial Indebtedness to EBITDA of 3.75 or less (as such terms are described in the loan agreements). At December 31, 2013, OTH’s ratio of Stockholders’ Equity to non-current assets, the ratio of EBITDA to Total Debt Service and the ratio of Net Financial Indebtedness to EBITDA (as such terms are defined in the loan agreements) were 60.2%, 15.3 and 1.35, respectively. At December 31, 2013, OTH was in compliance with all covenants contained in the loan agreements.
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OILT Credit Agreement
On November 7, 2012, OILT entered into Addendum No. 2 to its unsecured revolving line of credit agreement with OT Finance to increase the amount of the revolving credit commitment from $50.0 million to $150.0 million and to extend the maturity date from June 30, 2013 to November 30, 2017 (as amended, the “Credit Agreement”). From time to time upon OILT’s written request and in the sole determination of OT Finance, the revolving credit commitment can be increased up to an additional $75.0 million, for a maximum revolving credit commitment of $225.0 million. Borrowings bear interest at LIBOR plus a margin ranging from 1.65% to 2.50% depending upon a leverage-based grid. Any unused portion of the revolving line of credit is subject to a commitment fee of 0.35% per annum. OILT paid an arrangement fee of $0.5 million to OT Finance in November 2012 in connection with the amendment, the expense of which has been deferred and is being amortized over the term of the Credit Agreement. In November 2013, OILT repaid $56.0 million outstanding under the Credit Agreement with proceeds from our public offering of units (see Note 9). As of December 31, 2013, OILT had no borrowings outstanding under the Credit Agreement. As of December 31, 2012, OILT had $6.0 million of outstanding borrowings under the Credit Agreement at a weighted average interest rate of 2.44% per annum.
The Credit Agreement requires OILT to maintain, on an calendar year basis, certain Financial Parameters (as such term is defined in the Credit Agreement), including: (i) a ratio of Stockholders’ Equity to non-current assets of 30% or greater, (ii) a ratio of EBITDA to Total Debt Service of 1.2 or greater and (iii) a ratio of Net Financial Indebtedness to EBITDA of 3.75 or less (as such terms are defined in the Credit Agreement). At December 31, 2013, OILT’s ratio of Stockholders’ Equity to non-current assets, the ratio of EBITDA to Total Debt Service and the ratio of Net Financial Indebtedness to EBITDA (as such terms are defined in the Credit Agreement) were 83.5%, 2.2 and 1.19, respectively. At December 31, 2013, OILT was in compliance with all covenants contained in the Credit Agreement.
9. PARTNERS’ CAPITAL AND DISTRIBUTIONS
Summary of Changes in Outstanding Units
The following is a reconciliation of our limited partner units outstanding for the periods indicated:
Limited Partner Units | ||||||||
Common | Subordinated | Total | ||||||
Limited partner units outstanding at December 31, 2010 | — | — | — | |||||
Units issued in exchange for contribution of net assets to OILT | 7,949,901 | 19,449,901 | 27,399,802 | |||||
Units issued in IPO on July 19, 2011 | 11,500,000 | — | 11,500,000 | |||||
Limited partner units outstanding at December 31, 2011 | 19,449,901 | 19,449,901 | 38,899,802 | |||||
Units issued in 2012 | — | — | — | |||||
Limited partner units outstanding at December 31, 2012 | 19,449,901 | 19,449,901 | 38,899,802 | |||||
Units issued in public offering in November 2013 | 2,600,000 | — | 2,600,000 | |||||
Limited partner units outstanding at December 31, 2013 | 22,049,901 | 19,449,901 | 41,499,802 | |||||
Initial Public Offering
As discussed in Note 1, in connection with the closing of our IPO, OTA and its affiliates contributed their interests in OTH and OTB to us, and we issued an aggregate of 7,949,901 common units and 19,449,901 subordinated units, both of which represent limited partner interests, to OTA and its affiliates, and issued IDRs to our general partner.
On July 19, 2011, we issued 11,500,000 common units to the public, which included 1,500,000 common units issued pursuant to the underwriters’ exercise of their over-allotment option. The net proceeds from our IPO of approximately $231.2 million, after deducting underwriting discounts and structuring fees, were used to: (i) repay intercompany indebtedness owed to OT Finance in the amount of approximately $119.5 million, (ii) pay OT Finance for approximately $1.0 million of interest due on intercompany indebtedness and reimburse OT Finance for approximately $6.4 million of fees incurred in connection with the repayment of such indebtedness, (iii) make
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distributions to OTA and its affiliates in the aggregate amount of $77.2 million, (iv) pay other offering expenses of approximately $3.4 million and (v) provide us working capital of approximately $23.7 million.
Equity Offering
On November 22, 2013, we completed a public offering of 2,600,000 common units at a price to the public of $61.65 per unit. The proceeds from the offering, net of underwriting discounts and other offering expenses, totaled approximately $154.3 million and were used to repay outstanding balances under the Credit Agreement, fund capital projects and for general partnership purposes. In connection with the offering, our general partner contributed an additional $3.3 million to us to maintain its 2.0% general partner interest in us.
Distributions
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date.
The following table details the distributions paid during or pertaining to the years ended December 31, 2013, 2012 and 2011 (in thousands, except per unit amounts):
Common and | General | Incentive | Distributions | |||||||||||||||||||
Date Paid | Subordinated | Partner’s | Distribution | per Limited | ||||||||||||||||||
Date Declared | or To Be Paid | Units | 2% Interest | Rights | Total | Partner Unit | ||||||||||||||||
October 20, 2011 | November 14, 2011 | $ | 10,418 | $ | 212 | $ | — | $ | 10,630 | $ | 0.2678 | |||||||||||
January 23, 2012 | February 14, 2012 | $ | 13,226 | $ | 270 | $ | — | $ | 13,496 | $ | 0.34 | |||||||||||
April 23, 2012 | May 14, 2012 | $ | 13,614 | $ | 278 | $ | — | $ | 13,892 | $ | 0.35 | |||||||||||
July 19, 2012 | August 14, 2012 | $ | 14,004 | $ | 286 | $ | — | $ | 14,290 | $ | 0.36 | |||||||||||
October 18, 2012 | November 14, 2012 | $ | 14,588 | $ | 298 | $ | — | $ | 14,886 | $ | 0.375 | |||||||||||
January 22, 2013 | February 14, 2013 | $ | 15,171 | $ | 310 | $ | 11 | $ | 15,492 | $ | 0.39 | |||||||||||
April 22, 2013 | May 14, 2013 | $ | 15,754 | $ | 324 | $ | 100 | $ | 16,178 | $ | 0.405 | |||||||||||
July 22, 2013 | August 14, 2013 | $ | 16,532 | $ | 342 | $ | 238 | $ | 17,112 | $ | 0.425 | |||||||||||
October 21, 2013 | November 14, 2013 | $ | 17,310 | $ | 363 | $ | 477 | $ | 18,150 | $ | 0.445 | |||||||||||
January 21, 2014 | February 14, 2014 | $ | 19,505 | $ | 415 | $ | 827 | $ | 20,747 | $ | 0.47 | |||||||||||
Our partnership agreement requires that we distribute all of our available cash (as defined in our partnership agreement) each quarter in the following manner:
• | first, 98.0% to the holders of our common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $0.3375 plus any arrearages from prior quarters; |
• | second, 98.0% to the holders of our subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $0.3375; and |
• | third, 98.0% to all unitholders pro rata, and 2.0% to our general partner, until each unit has received a quarterly distribution of $0.38813. |
The general partner’s IDRs provide that if cash distributions to our unitholders exceed $0.38813 per common unit and subordinated unit in any quarter, our unitholders and our general partner will receive, including its 2.0% general partner interest, distributions according to the following percentage allocations:
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Target Quarterly Distribution Target Amount | Marginal Percentage Interest in Distributions | ||||
Unitholders | General Partner | ||||
Minimum quarterly distribution | $0.3375 | 98.0% | 2.0% | ||
First target distribution | above $0.3375 up to $0.38813 | 98.0% | 2.0% | ||
Second target distribution | above $0.38813 up to $0.42188 | 85.0% | 15.0% | ||
Third target distribution | above $0.42188 up to $0.50625 | 75.0% | 25.0% | ||
Thereafter | above $0.50625 | 50.0% | 50.0% | ||
Our general partner, as the initial holder of all of our IDRs, has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%, in addition to distributions paid on its 2.0% general partner interest) for each of the prior four consecutive whole fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and a general partner interest necessary to maintain its general partner interest in us immediately prior to the reset election. The number of common units to be issued to our general partner will equal the number of common units that would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the IDRs in such prior two quarters.
If our general partner transfers all or a portion of the IDRs in the future, then the holder or holders of a majority of our IDRs will be entitled to exercise the reset election. Assuming our general partner holds all of the IDRs at the time a reset election is made, following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution as the current target distribution levels.
Subordinated Units
All of our subordinated units are owned directly or indirectly by OTA. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution (defined below) plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.
The subordination period will end on the first business day after we have earned and paid at least: (i) $1.35 (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2014; or (ii) $2.025 (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner’s 2.0% interest and the related distribution on the IDRs for the four-quarter period immediately preceding that date, in each case provided there are no arrearages on our common units at that time. Since our IPO in July 2011, we have paid at least the minimum quarterly distribution on our common units in all quarters. If we continue to pay distributions from available cash and generate operating surplus (as defined in our partnership agreement) at a rate consistent with prior periods, the subordination period is expected to end following our payment of the distribution for the quarter ending September 30, 2014.
The subordination period also will end upon the removal of our general partner other than for cause if no subordinated units or common units held by the holder(s) of subordinated units or their affiliates are voted in favor of that removal.
When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and thereafter no common units will be entitled to arrearages.
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10. EARNINGS PER LIMITED PARTNER UNIT
The following table sets forth the computation of basic and diluted earnings per limited partner unit for the periods indicated (amounts in thousands, except per unit data):
July 19, 2011 | |||||||||||
Year Ended | through | ||||||||||
December 31, | December 31, | ||||||||||
2013 | 2012 | 2011 | |||||||||
Net income | $ | 117,063 | $ | 62,645 | $ | 62,397 | |||||
Net income prior to IPO on July 19, 2011 | — | — | (38,591 | ) | |||||||
Net income subsequent to IPO on July 19, 2011 | 117,063 | 62,645 | 23,806 | ||||||||
Less: General partner’s incentive distribution earned (1) | 19,755 | 237 | — | ||||||||
Less: General partner’s 2.0% ownership interest | 2,341 | 1,252 | 476 | ||||||||
Net income allocated to limited partners | $ | 94,967 | $ | 61,156 | $ | 23,330 | |||||
Numerator for basic and diluted earnings per limited partner unit: | |||||||||||
Allocation of net income among limited partner interests: | |||||||||||
Net income allocable to common units | $ | 48,326 | $ | 30,578 | $ | 11,665 | |||||
Net income allocable to subordinated units | 46,641 | 30,578 | 11,665 | ||||||||
Net income allocated to limited partners | $ | 94,967 | $ | 61,156 | $ | 23,330 | |||||
Denominator: | |||||||||||
Basic and diluted weighted average number of limited partner units outstanding: | |||||||||||
Common units | 19,735 | 19,450 | 19,450 | ||||||||
Subordinated units | 19,450 | 19,450 | 19,450 | ||||||||
Basic and diluted net income per limited partner unit: | |||||||||||
Common units | $ | 2.45 | $ | 1.57 | $ | 0.60 | |||||
Subordinated units | $ | 2.40 | $ | 1.57 | $ | 0.60 | |||||
____________
(1) | Based on the amount of net income for the years ended December 31, 2013 and 2012, our general partner was allocated income associated with its IDRs for these periods. Under the two-class method, because our partnership agreement does not limit distributions to our general partner with respect to IDRs to available cash, we allocate undistributed earnings to our general partner utilizing the distribution waterfall for available cash specified in our partnership agreement. Cash payments made to our general partner and limited partners are determined in relation to actual distributions declared and are not based on the net income allocations used in the calculation of earnings per unit. |
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11. EMPLOYEE BENEFITS
401(K) Retirement Plan
We previously sponsored a retirement plan which is available to all employees who have six months of continuous service and covers all employees of OTA. The plan is subject to the provisions of the Employee Retirement Income Security Act of 1974 and is qualified under Section 401(k) of the Internal Revenue Code. The contributions to the plan, as determined by management, are discretionary but may not exceed the maximum amount deductible under the applicable provisions of the Internal Revenue Code. Historically, we made contributions into the plan on behalf of all OTA subsidiaries and were then reimbursed by the related subsidiary. Our contributions to the retirement plan, net of amounts charged to other OTA entities, was $0.8 million for the year ended December 31, 2011. Effective June 1, 2011, in anticipation of our IPO, our former employees were transferred to OTA, and OTA became the sponsor of the 401(k) retirement plan. Subsequent to our entry into the Services Agreement (see Note 3), costs for the 401(k) retirement plan are incurred by OTA and billed to us by OTA pursuant to the Services Agreement.
Deferred Compensation Plan
Effective August 15, 1994, we adopted a special non-qualified deferred compensation plan for the purpose of providing deferred compensation to certain employees. The plan provides for elective salary deferrals by participants and discretionary contributions by us as defined by the plan. We recognized $0.1 million of accrued compensation to participants for the year ended December 31, 2011. Payments of accrued compensation totaled $0.2 million for the year ended December 31, 2011. We purchased life insurance policies on certain of our employees and invested in mutual funds to assist in funding the deferred compensation liability. All payments of accrued compensation to participants were funded by our operating cash flows. Employee deferrals totaled $0.4 million for the year ended December 31, 2011. The deferred compensation liability was determined by hypothetical investment accounts based on actual mutual funds or money market funds selected by each participant. On June 1, 2011, in anticipation of our IPO, the deferred compensation plan obligations, related insurance policies and mutual funds, along with our former employees, were transferred to OTA. Subsequent to our entry into the Services Agreement (see Note 3), costs for the deferred compensation plan are incurred by OTA and billed to us by OTA pursuant to the Services Agreement.
12. MEDICAL INSURANCE AND POSTRETIREMENT BENEFIT OBLIGATIONS
Medical Insurance
Prior to June 1, 2011, we sponsored a self-insurance program for medical and dental insurance administered by a third party, which covered all of our former employees. The total expense and obligations to the administrator was a result of administrative fees, premiums and actual incidence of claims. Under the program, we were responsible for a predetermined limit of claims per participant per year, or a maximum of approximately $3.0 million to $4.0 million in the aggregate per year, in accordance with the plan agreements. Claims exceeding these amounts were covered by an insurance policy. Effective June 1, 2011, our former employees were transferred to OTA, and OTA became the sponsor of the self-insurance program. Subsequent to our entry into the Services Agreement (see Note 3), costs for the insurance program plan are incurred by OTA and billed to us by OTA pursuant to the Services Agreement.
Postretirement Benefit Plan
Effective June 1, 2004, we established a non-pension postretirement benefit plan. The plan was designed to provide health care coverage, upon retirement, to the employees of OTA who met the age and service requirements. The health plan was contributory, with participants’ contributions adjusted annually. We were required to reflect the funded status of the defined benefit postretirement health plan as a prepaid asset or an accrued liability and to recognize the net deferred and unrecognized gains and losses, net of tax, as part of accumulated other comprehensive income within partners’ capital. We used a December 31 measurement date for the plan. Effective June 1, 2011, OTA became the sponsor of the postretirement benefit plan, and our obligations under this plan along with our former employees were transferred to OTA. Subsequent to our entry into the Services Agreement (see Note 3), costs for the postretirement benefit plan are incurred by OTA and billed to us by OTA pursuant to the Services Agreement.
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The following table presents our net periodic benefit costs for the period indicated (in thousands):
Year Ended December 31, | ||||
2011 | ||||
Service cost | $ | 447 | ||
Interest cost | 190 | |||
Amortization of unrecognized amounts: | ||||
Prior service cost | 47 | |||
Net actuarial loss | 11 | |||
Net periodic benefit costs | $ | 695 | ||
The following table presents changes in plan assets and benefit obligations recognized in other comprehensive income (loss) for the period indicated (in thousands):
Year Ended December 31, | |||
2011 | |||
Current period net loss | $ | (153 | ) |
Amortization of prior service cost | 47 | ||
Amortization of prior net actuarial loss | 11 | ||
Total recognized in other comprehensive loss | (95 | ) | |
Net periodic postretirement benefit cost | (695 | ) | |
Total recognized in net periodic postretirement benefit cost | |||
and other comprehensive income | $ | (790 | ) |
The assumptions used in determining net benefit cost were as follows for the period indicated:
Year Ended December 31, | |
2011 | |
Weighted average expense assumptions: | |
Discount rate at the beginning of year | 5.68% |
Initial health care cost trend rate (1) | 9.50% |
Ultimate health care cost trend rate | 5.00% |
Number of years to reach ultimate trend | 10 |
__________
(1) | Rate represents assumed medical cost trend rate for all employee costs. Drug costs have a trend rate of 8.5%. |
The discount rates are based on a discount rate analysis using the Citigroup Pension Discount Curve and the expected postretirement benefit cash flows. The resulting discount rates are consistent with the duration of plan liabilities.
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13. INTEREST EXPENSE
The following table presents the components of interest costs incurred for the periods indicated (in thousands):
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Related party interest expense | $ | (9,509 | ) | $ | (3,377 | ) | $ | (6,032 | ) | ||
Capitalized related party interest | 2,140 | 1,749 | 619 | ||||||||
Other | (24 | ) | (26 | ) | (25 | ) | |||||
Total interest expense | $ | (7,393 | ) | $ | (1,654 | ) | $ | (5,438 | ) | ||
14. MAJOR CUSTOMERS
The following table presents the percentage of revenues and receivables associated with our significant customers for the periods indicated:
% of Revenues | % of Receivables | |||||||||||||
Year Ended December 31, | December 31, | |||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | ||||||||||
Enterprise Products Partners L.P. | 29 | % | 13 | % | 12 | % | 38 | % | 15 | % | ||||
ExxonMobil Corporation | 9 | % | 11 | % | 12 | % | 2 | % | 10 | % | ||||
LyondellBasell Industries, N.V. | 9 | % | 12 | % | 13 | % | 11 | % | 3 | % | ||||
BP p.l.c. | 8 | % | 16 | % | 15 | % | 6 | % | 18 | % | ||||
Royal Dutch Shell plc | 7 | % | 9 | % | 11 | % | 10 | % | 15 | % | ||||
Total percentages associated with significant customers | 62 | % | 61 | % | 63 | % | 67 | % | 61 | % | ||||
No other customer accounted for more than 10% of our revenues during the years ended December 31, 2013, 2012 and 2011.
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15. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands):
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Cash paid for interest of $9,369, $2,888 and $13,020 (net of capitalized interest) (1) | $ | 7,229 | $ | 1,139 | $ | 12,401 | |||||
Cash taxes paid | 943 | 1,210 | 1,686 | ||||||||
Interest costs capitalized | 2,140 | 1,749 | 619 | ||||||||
Non-cash transactions: | |||||||||||
Change in accounts payable related to capital expenditures | $ | 7,383 | $ | 12,732 | $ | — | |||||
Distribution of certain land parcels and office building to OTA (2) | — | — | 6,215 | ||||||||
Distribution of certain accounts and notes receivable to OTA (2) | — | — | 18,277 | ||||||||
Transfer of postretirement plan obligation to OTA (including $1.7 million of accumulated other comprehensive loss) (2) | — | — | (8,824 | ) | |||||||
Transfer of deferred compensation plan obligations to OTA (2) | — | — | (4,124 | ) | |||||||
Transfer of deferred compensation plan assets to OTA (2) | — | — | 4,010 | ||||||||
Net deferred tax assets related to assets and liabilities transferred to OTA (2) | — | — | 4,531 | ||||||||
Cash distribution payable (3) | — | — | 178 | ||||||||
______________
(1) | 2011 amount includes $6.4 million of fees incurred in connection with the repayment of indebtedness in connection with our IPO (see Note 8). |
(2) | In connection with our IPO, OTH and OTB made non-cash distributions to OTA, consisting of certain land parcels, an office building and other property and equipment, certain accounts receivable and notes receivable, affiliate. In addition, the postretirement benefit and deferred compensation plans and obligations and certain assets to be used to fund the deferred compensation plan obligations were transferred to OTA. Related net deferred tax assets were also transferred to OTA. |
(3) | At December 31, 2011, we had an accrued pre-IPO distribution to OTA of $0.2 million, which was reflected in accounts payable, affiliates, and such amount was paid to OTA in the first quarter of 2012. During the year ended December 31, 2011, we paid pre-IPO distributions to OTA of $85.5 million, consisting of: (i) $2.0 million, which had been declared during December 2010 and paid in January 2011, and was included in accounts payable, affiliates at December 31, 2011, and (ii) $83.4 million, which was paid to OTA in July 2011, $77.0 million of which was paid using proceeds from the public issuance of common units. |
16. SEGMENT REPORTING
We derive our revenues from two operating segments — OTH and OTB. The two operating segments have been aggregated into one reportable business segment because they have similar long-term economic characteristics, types and classes of customers and provide similar services.
Revenues by service category are as follows for the periods indicated (in thousands):
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Storage service fees | $ | 120,245 | $ | 97,591 | $ | 87,794 | |||||
Throughput fees | 79,663 | 29,096 | 23,973 | ||||||||
Ancillary service fees | 11,042 | 8,810 | 5,610 | ||||||||
Total revenues | $ | 210,950 | $ | 135,497 | $ | 117,377 | |||||
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17. COMMITMENTS AND CONTINGENCIES
Litigation
In the ordinary course of business, we may be involved in various claims and legal proceedings, some of which are covered in whole or in part by insurance. We may not be able to predict the timing or outcome of these or future claims and proceedings with certainty, and an unfavorable resolution of one or more of such matters could have a material adverse effect on our financial condition, results of operations or cash flows. Currently, we are not party to any legal proceedings that, individually or in the aggregate, are reasonably likely to have a material adverse effect on our financial condition, results of operations or cash flows.
Environmental Liabilities
We may experience releases of crude oil, petroleum products and fuels, liquid petroleum gas or other contaminants into the environment, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may affect our business. As of December 31, 2013 and 2012, we have not identified any environmental obligations that would require an accrual in our consolidated financial statements.
Commitments
We have certain short-term purchase obligations and commitments for products and services, primarily related to construction on our expansion projects. At December 31, 2013, we had commitments of approximately $10.9 million for the purchase of property, plant and equipment.
Other
Our liquid storage and transport systems may experience damage as a result of an accident, natural disaster or terrorist activity. These hazards can cause personal injury and loss of life, severe damage to and destruction of property, and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance covers our assets in amounts we consider reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating our facilities, including the potential loss of significant revenues.
The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition.
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18. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for the years ended December 31, 2013 and 2012 is set forth below (in thousands, except per unit amounts):
First | Second | Third | Fourth | ||||||||||||||||
Quarter | Quarter | Quarter | Quarter | Total | |||||||||||||||
2013 | |||||||||||||||||||
Revenue | $ | 40,186 | $ | 52,079 | $ | 58,531 | $ | 60,154 | $ | 210,950 | |||||||||
Operating income | 21,234 | 31,378 | 35,774 | 37,114 | 125,500 | ||||||||||||||
Net income | 20,192 | 29,476 | 32,883 | 34,512 | 117,063 | ||||||||||||||
Earnings per common unit – basic and diluted (1) | $ | 0.48 | $ | 0.61 | $ | 0.65 | $ | 0.69 | $ | 2.45 | |||||||||
Earnings per subordinated unit – basic and diluted (1) | $ | 0.48 | $ | 0.61 | $ | 0.65 | $ | 0.65 | $ | 2.40 | |||||||||
2012 | |||||||||||||||||||
Revenue | $ | 34,286 | $ | 33,823 | $ | 33,327 | $ | 34,061 | $ | 135,497 | |||||||||
Operating income | 16,192 | 17,033 | 15,471 | 16,006 | 64,702 | ||||||||||||||
Net income | 15,939 | 16,621 | 14,907 | 15,178 | 62,645 | ||||||||||||||
Earnings per common unit – basic and diluted | $ | 0.40 | $ | 0.41 | $ | 0.38 | $ | 0.38 | $ | 1.57 | |||||||||
Earnings per subordinated unit – basic and diluted | $ | 0.40 | $ | 0.41 | $ | 0.38 | $ | 0.38 | $ | 1.57 | |||||||||
__________
(1) | The sum of the quarterly earnings per unit amounts do not equal the full year amounts due to rounding differences. |
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this Report at the reasonable assurance level.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate control over financial reporting. Our internal control over financial reporting is a process designed by, or under the supervision of, our general partner’s Chief Executive Officer and Chief Financial Officer, and effected by the board of directors of our general partner, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:
• | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; |
• | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and the board of directors of our general partner; and |
• | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisitions, use or disposition of our assets that could have a material effect on our financial statements. |
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
Management, with the participation of our general partner’s Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of our internal control over financial reporting as of December 31, 2013 based on the criteria for effective internal control over financial reporting established in “Internal Control — Integrated Framework (1992),” issued by the Committee of Sponsoring Organizations of the Treadway Commission. This assessment included design, effectiveness and operating effectiveness of internal controls over financial reporting as well as the safeguarding of assets. Based on that assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2013, based on those criteria.
BDO USA, LLP, the independent registered public accounting firm who also audited our Consolidated Financial Statements included in this Annual Report on Form 10-K, has issued an attestation report on our internal control over
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financial reporting as of December 31, 2013, which is set forth below under “Attestation Report of the Registered Public Accounting Firm.”
Attestation Report of the Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm
Board of Directors of OTLP GP, LLC, as General Partner of Oiltanking Partners, L.P. and
the Partners of Oiltanking Partners, L.P.
Houston, Texas
We have audited Oiltanking Partners, L.P.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Oiltanking Partners, L.P.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying “Item 9A. Controls and Procedures — Management’s Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on Oiltanking Partners, L.P.’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Oiltanking Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Oiltanking Partners, L.P. as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, cash flows and partners’ capital for each of the three years in the period ended December 31, 2013, and our report dated February 24, 2014 expressed an unqualified opinion thereon.
/s/ BDO USA, LLP
Houston, Texas
February 24, 2014
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Change in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) or in any other factors during our last fiscal quarter, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Our general partner manages our operations and activities on our behalf through its directors and officers, the latter of whom are employed by Oiltanking North America, LLC, a subsidiary of OTA (“OTNA”). Our general partner is not elected by our unitholders and is not subject to re-election in the future. The directors of our general partner oversee our operations. Unitholders are not entitled to elect the directors of our general partner, which are appointed by OTA as the sole member of our general partner. Unitholders are not entitled to directly or indirectly participate in our management or operations. Our general partner is, however, accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and our partnership agreement, which contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner.
Our general partner currently has seven directors, three of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors or to establish a compensation committee or a nominating committee. We are, however, required to have an audit committee of at least three members, and all of the audit committee members are required to meet the independence and experience standards established by the NYSE and the Exchange Act. The board of directors of our general partner has determined that the members of the audit committee meet these standards.
All of the executive officers of our general partner listed below allocate their time between managing our business and the business of OTA and its other affiliates. While the amount of time that our executive officers devote to our business varies in any given year, our executive officers intend to devote as much time as necessary for the proper conduct of our business.
Under the Services Agreement, we pay OTNA an annual fixed fee, payable in monthly installments, for expenses associated with certain specified selling, general and administrative services necessary to run our business that are provided to us by OTNA. These expenses include expenses of executive and non-executive employees, including general and administrative overhead costs, salary, bonus, incentive compensation and other compensation amounts. Our general partner, OTNA and OTA do not receive any other management fee or other compensation in connection with our general partner’s management of our business, but we reimburse our general partner and its affiliates, including OTNA, for all expenses they incur and payments they make on our behalf, other than expenses associated with the fixed fee. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us but does not limit the amount of expenses for which our general partner and its affiliates may be compensated.
In evaluating director candidates, OTA assesses whether a candidate possesses the judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of the board of directors to oversee our affairs and business, including, when applicable, to enhance the ability of committees of the board of directors to fulfill their duties.
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Executive Officers and Directors of our General Partner
The following table shows information for the executive officers and directors of our general partner. Directors are appointed and hold office until their successors have been appointed or until the earlier of their death, resignation, removal or disqualification. Our board of directors appoints our executive officers, who are responsible for our day-to-day business and affairs, subject to the overall direction and control of our board of directors. Our executive officers are appointed for terms as determined by our board of directors. There are no family relationships among any of our directors or executive officers. Some of our directors and all of our executive officers also serve as executive officers of OTA and its affiliates.
Name | Age | Position With Our General Partner |
Anne-Marie Ainsworth | 57 | President, Chief Executive Officer and Director |
Jonathan Z. Ackerman | 40 | Vice President and Chief Financial Officer |
Robert J. “Bo” McCall | 49 | Senior Vice President, Commercial and Business Development |
Brian C. Brantley | 36 | Vice President, General Counsel and Secretary |
Kevin L. Campbell | 49 | Vice President, Operations |
Clayton K. Curtis | 55 | Vice President, Regulatory Affairs |
Javier Del Olmo B. | 40 | Vice President, Engineering |
Kim M. Ivy | 56 | Vice President, Business Planning and Strategy |
Carlin G. Conner | 46 | Chairman of the Board and Director (1) |
James Flannan Browne | 65 | Director |
David L. Griffis | 68 | Director |
Thomas M. Hart III | 47 | Director (2) |
Gregory C. King | 53 | Director (2) |
D. Mark Leland | 52 | Director (2) |
_________________
(1) | On February 18, 2014, we announced that Mr. Connor notified us of his intention to resign from his positions with the Oiltanking Group and our general partner. We expect that Mr. Conner will continue in his current roles until a successor is appointed. |
(2) | Director is an independent director of our general partner and is not otherwise affiliated with our general partner or OTA, or their affiliates. |
Ms. Ainsworth has served as President and Chief Executive Officer and a member of the board of directors of our general partner and as President and Chief Executive Officer of OTA since November 2012. Prior to joining the Oiltanking Group, Ms. Ainsworth previously held the position of Senior Vice President of Sunoco Refining from November 2009 until March 2012. Prior to joining Sunoco, Ms. Ainsworth was employed by Motiva Enterprises, LLC, where she was the General Manager of the Motiva refinery in Norco, Louisiana from November 2006 to October 2009. From December 2003 to November 2006, Ms. Ainsworth was Director of Management Systems & Process Safety at Shell Oil Products U.S., and from September 2000 to December 2003, she was Vice President of Technical Assurance at Shell’s Deer Park refinery. Ms. Ainsworth holds a Master’s degree in Business Administration from Rice University, where she served as an adjunct professor from October 2000 to October 2009, and a Bachelor’s degree in Chemical Engineering. We believe Ms. Ainsworth, with her extensive management experience in leadership positions across the refining industry, provides valuable insight to the board of directors of our general partner.
Mr. Ackerman has served as Vice President and Chief Financial Officer of our general partner and Vice President and Chief Financial Officer of OTA since July 2013. Prior to joining the Oiltanking Group, Mr. Ackerman worked for UBS Investment Bank beginning in April 2006, where he was most recently Managing Director, Mergers & Acquisitions and Co-Head, Strategic Solutions Group. Prior to joining UBS, Mr. Ackerman served as Senior Counsel and lead technical policy advisor to President George W. Bush’s Advisory Panel on Federal Tax Reform from February 2005 to December 2005. Mr. Ackerman was a policy advisor in the U.S. Department of the Treasury’s Office of Tax Policy from October 2003 to February 2005 and from December 2005 to March 2006. As an attorney in private practice from
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1999 to 2003, he advised large businesses on complex transactions. Mr. Ackerman is a Certified Public Accountant (CPA) and began his career with a leading global public accounting firm.
Mr. McCall has served as Senior Vice President of Commercial and Business Development of our general partner and as Senior Vice President of Commercial and Business Development of OTA since January 2013. Prior to January 2013, Mr. McCall was Vice President of Marketing and Sales of our general partner from March 2011 and Vice President of Marketing and Sales of OTA from March 2007. Mr. McCall has been in the midstream oil and gas business for 26 years. Prior to joining the Oiltanking Group in 2003, he worked for Conoco and other small oil and gas companies with responsibilities ranging from engineering, sales, commercial and executive capacities. At OTA, he has worked in the commercial department as a sales manager for six years and as the Vice President of Marketing for an additional seven years supporting all of OTA’s facilities.
Mr. Brantley has served as Vice President, General Counsel and Secretary of our general partner and Vice President, General Counsel and Secretary of OTA since September 2012. Prior to joining the Oiltanking Group, Mr. Brantley practiced corporate law at Vinson & Elkins LLP from April 2006 through August 2012, and at Cravath, Swaine & Moore LLP from September 2003 through March 2006. Mr. Brantley has represented public and private companies, investment funds and investment banking firms in numerous mergers and acquisitions and capital markets transactions, primarily in the energy industry.
Mr. Campbell has served as Vice President of Operations of our general partner since March 2011 and Vice President of Operations of OTA since April 2010. Prior to that, he was the Terminal Manager for Oiltanking Texas City, L.P., a wholly owned subsidiary of OTA, from January 2008 until April 2010. Prior to becoming Terminal Manager, he served as the Operations Manager for Oiltanking Texas City, L.P. from July 2004 until January 2008. Mr. Campbell has been employed by the Oiltanking Group since 1985, serving in various roles, including operations, scheduling and health, safety and environmental.
Mr. Curtis has served as Vice President of Regulatory Affairs of our general partner since February 2013 and as Vice President of Regulatory Affairs of OTA since January 2010. Prior to January 2010, Mr. Curtis was Director of Regulatory Affairs for OTA from July 2007 to January 2010. Prior to joining the Oiltanking Group in 2007, Mr. Curtis worked for Baker Hughes Incorporated for twenty years, including seventeen years in various positions in the corporate regulatory affairs and health and safety department. Mr. Curtis has been a certified safety professional since 1990 and has served as a member of the board of directors on the Houston Ship Channel Security District since its inception in 2010.
Mr. Del Olmo has served as Vice President of Engineering of our general partner since February 2013 and as Vice President of Engineering of OTA since January 2013. Prior to that, he was General Manager of Engineering for OTA from June 2011 until December 2012 and Business Development Manager of OTA from June 2010 to June 2011. Prior to becoming Business Development Manager, Mr. Del Olmo was Trading Business Development Manager in Latin America for the Oiltanking Group from January 2009 to June 2010, managing director of Oiltanking Mexico from June 2008 to August 2010, and commercial director for Oiltanking Mexico from June 2005 to June 2008. Mr. Del Olmo has been employed by the Oiltanking Group since 1997, serving in various roles, including project coordinator, business development, commercial and operations. Mr. Del Olmo has been a member of the board of directors and has served as a legal representative for Oiltanking Mexico since June 2008.
Mr. Ivy has served as Vice President of Business Planning and Strategy of our general partner and as Vice President of Business Planning and Strategy of OTA since November 2013. Prior to that, Mr. Ivy was Vice President of Business Development of OTA from June 2011 until October 2013 and was Vice President of Business Development of our general partner from February 2013 until October 2013. Prior to becoming Vice President of Business Development, Mr. Ivy was Vice President and Terminal Manager of OTB and Oiltanking Port Neches, LLC from September 2008 until May 2011. Prior to becoming Vice President and Terminal Manager, he served as Vice President of Finance of OTA from 2000 to August 2008. Mr. Ivy has been employed by the Oiltanking Group since July 1982, serving in various roles primarily related to accounting, administration and finance.
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Mr. Conner has served as a member of the board of directors of our general partner since March 2011 and was elected Chairman of the board of directors of our general partner in July 2011 in connection with the completion of our IPO. Mr. Conner also served as President and Chief Executive Officer of our general partner from March 2011 to November 2012 and President and Chief Executive Officer of OTA from July 2006 to November 2012. On June 25, 2012, Mr. Conner was appointed Managing Director of the Oiltanking Group. Mr. Conner has been in the terminaling business for over twenty years. Before joining the Oiltanking Group, he worked at GATX Terminals Corporation in various roles including operations and commercial management. In 2000, he joined Oiltanking Houston, L.P. and in 2003, he moved to the Oiltanking Group’s corporate headquarters in Hamburg, Germany, where he was responsible for international business development. In Hamburg, he sat on the boards of several Oiltanking Group ventures. We believe that Mr. Conner’s experience as President and Chief Executive Officer of OTA and as Managing Director of the Oiltanking Group and related familiarity with our assets as well as his extensive knowledge of the terminaling industry brings substantial experience and leadership skills to the board of directors of our general partner.
Mr. Browne was appointed to serve as a member of the board of directors of our general partner in January 2012. Mr. Browne has served as the Head of Legal and Insurance for Oiltanking GmbH since April 2004. From February 2001 to April 2004, he served as a legal advisor for Skytanking Holding GmbH, an affiliate of Oiltanking GmbH that specializes in construction, operation and management of airport fuel facilities. During 2002, he also started working as a legal advisor to the Oiltanking Group. Mr. Browne has been practicing law since 1977. After working for the law firm of Coudert Brothers in its New York and London offices, in September 1984, he joined Greyhound Financial Services in London as the head of the legal department, where his work included aircraft and ship financing as well as legal work for other European affiliates of Greyhound, including the Aircraft Service International Group (“ASIG”). From November 1996 to December 2000, he served as ASIG’s European counsel. Mr. Browne currently serves as a director for multiple international entities affiliated with the Oiltanking Group. We believe that Mr. Browne’s various roles with affiliates of the Oiltanking Group over the last decade provide significant experience and skills relating to our operations, making him a valuable member of the board of directors of our general partner.
Mr. Griffis has served as a member of the board of directors of our general partner since March 2011. He has served as outside counsel for Oiltanking Houston, L.P. since its inception in 1974. Mr. Griffis has been practicing law since 1974, and is currently a shareholder at the law firm of Crain, Caton & James, P.C., where he represents domestic and international clients in acquisitions, joint ventures and strategic alliances. Crain, Caton & James, P.C. provides legal counsel to us, as well as to OTA and certain of its other affiliates. We believe that Mr. Griffis’s nearly four decades of experience in transactional law and extensive knowledge of the Oiltanking Group’s business and operations brings unique and valuable skills to the board of directors.
Mr. Hart was appointed to serve as a member of the board of directors of our general partner in February 2014. Mr. Hart serves as a member of both the Audit and Conflicts Committees of the board of directors of our general partner. Mr. Hart is President of Maverick American Natural Gas, LLC, a privately held acquisition-focused oil and natural gas production company. Mr. Hart has held this position since September 2011. From August 2010 to September 2011, he was engaged in the process of organizing, financing and launching Maverick American Natural Gas. Prior to that, Mr. Hart served as an officer of El Paso Corporation and its subsidiaries in various capacities beginning in January 2001. Mr. Hart served as Senior Vice President of Commercial Development for El Paso’s midstream business unit from November 2009 to July 2010, as Senior Vice President of Business Development and Law for El Paso Exploration and Production Company from January 2005 to November 2009, as Vice President of Corporate Development for El Paso Corporation from September 2002 to January 2005, and as Director of Mergers and Acquisitions from January 2001 to September 2002. Mr. Hart began his career as an attorney in the corporate and securities group of Andrews & Kurth, LLP, a Houston-based law firm. The board of directors has determined that Mr. Hart is “independent” under applicable NYSE rules. Mr. Hart brings extensive management, financial and transaction experience in the upstream and midstream segments of the energy industry to the board of directors of our general partner.
Mr. King was appointed to serve as a member of the board of directors of our general partner in connection with our IPO. Mr. King also serves as the chairman of the Conflicts Committee and as a member of the Audit Committee of the board of directors of our general partner. Mr. King previously served as President of Valero Energy Corporation from January 2003 to December 2007. Mr. King served as Executive Vice President and General Counsel of Valero Energy from September 2001 until December 2002, and as Executive Vice President and Chief Operating Officer from
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January 2001 until September 2001. Prior to that, he served as Senior Vice President and Chief Operating Officer of Valero Energy from 1999 to January 2001. He became Vice President and General Counsel of Valero Energy in 1997, and prior to that was a Partner in the Houston-based law firm of Bracewell & Giuliani. From January 1, 2002 until July 2006, Mr. King served as director of the general partner of Valero L.P. (currently known as NuStar Energy L.P.). Mr. King has served on the board of directors of the general partner of QEP Midstream Partners, LP since November 2013. The board of directors has determined that Mr. King is “independent” under applicable NYSE rules and qualifies as an “Audit Committee Financial Expert.” Mr. King brings demonstrated industry knowledge, derived from over 25 years of energy industry experience, and communications, team-building and leadership skills to the board of directors of our general partner.
Mr. Leland was appointed to serve as a member of the board of directors of our general partner in May 2012. Mr. Leland also serves as a member of both the Audit and Conflicts Committees of the board of directors of our general partner. Mr. Leland served as Executive Vice President of El Paso Corporation and President of El Paso’s midstream business unit from October 2009 to May 2012, and as Director of El Paso Pipeline Partners, L.P. from its formation in 2007 to May 2012. Mr. Leland also previously served as Executive Vice President and Chief Financial Officer of El Paso Corporation from August 2005 to November 2009. He served as Executive Vice President of El Paso Exploration & Production Company from January 2004 to August 2005, and as Chief Financial Officer and a director from April 2004 to August 2005. Mr. Leland served as Senior Vice President and Chief Operating Officer of the general partner of GulfTerra Energy Partners, L.P. from January 2003 to December 2003, and as Senior Vice President and Controller from July 2000 to January 2003. Mr. Leland has served on the board of directors of KiOR, Inc. since May 2013. The board of directors has determined that Mr. Leland is “independent” under applicable NYSE rules and qualifies as an “Audit Committee Financial Expert.” Mr. Leland brings extensive operational and financial experience in the midstream energy industry to the board of directors of our general partner.
Director Independence
The board of directors of our general partner has determined that each of Messrs. Hart, King and Leland are independent as defined under the independence standards established by the NYSE and the Exchange Act. Randall J. Larson, who served as a member of the board of directors of our general partner until February 19, 2014, was independent as defined under these standards, and qualified as an “Audit Committee Financial Expert.”
Committees of the Board of Directors
Our general partner’s board of directors has two standing committees: the Audit Committee and Conflicts Committee.
Audit Committee
The Audit Committee of our general partner has been established in accordance with Section 3(a)(58)(A) of the Exchange Act, and consists of Messrs. Hart, King and Leland, all of whom are independent. Mr. Leland is the current Chairman of the Audit Committee. The board of directors of our general partner has determined Mr. Leland is an “audit committee financial expert” within the meaning of the SEC rules. Our Audit Committee operates pursuant to a written charter, an electronic copy of which is available on our website at www.oiltankingpartners.com.
The Audit Committee of the board of directors of our general partner serves as our Audit Committee and assists the board of directors in its oversight of the integrity of our consolidated financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The Audit Committee has the sole authority to (i) retain and terminate our independent registered public accounting firm, (ii) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (iii) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the Audit Committee and our management, as necessary.
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Conflicts Committee
Messrs. Hart, King and Leland serve on the Conflicts Committee. Mr. King is the current Chairman of the Conflicts Committee. The Conflicts Committee reviews specific matters that the board of directors believes may involve conflicts of interest (including certain transactions with members of the Oiltanking Group). The Conflicts Committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, including OTA, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.
Executive Sessions of Non-Management Directors
The board of directors of our general partner holds regular executive sessions in which the independent directors meet without any non-independent directors or members of management. The purpose of these executive sessions is to promote open and candid discussion among the independent directors. The rules of the NYSE require that one of the independent directors must preside over each executive session, and the role of presiding director is rotated among each of the independent directors.
Communication with the Board of Directors
A holder of our units or other interested party who wishes to communicate with the non-management directors of our general partner may do so by contacting our corporate secretary at the address or phone number appearing on the front page of this Report. Communications will be relayed to the intended recipient of the board of directors of our general partner except in instances where it is deemed unnecessary or inappropriate to do so pursuant to the procedures established by the Audit Committee. Any communications withheld under those guidelines will nonetheless be recorded and available for any director who wishes to review them.
Corporate Governance Matters
We have a Code of Ethics for Directors, Executive Officers and Senior Financial Employees that applies to, among others, the Chairman, Chief Executive Officer, President, Chief Financial Officer and Controller of our general partner, as required by Section 406 of the Sarbanes-Oxley Act of 2002. Furthermore, we have Corporate Governance Guidelines and a charter for our Audit Committee. Each of the foregoing is available on our website at www.oiltankingpartners.com in the “Corporate Governance” section. We provide copies, free of charge, of any of the foregoing upon receipt of a written request. We disclose amendments and director and executive officer waivers with regard to the Code of Ethics, if any, on our website or by filing a Current Report on Form 8-K to the extent required.
You can also find information about us at the offices of the NYSE, 20 Broad Street, New York, New York 10005 or at the NYSE’s website at www.nyse.com. The certifications of our general partner’s Chief Executive Officer and Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act have been included as exhibits to this Report.
NYSE Corporate Governance Listing Standards
The NYSE requires the chief executive officer of each listed company to certify annually that he is not aware of any violation by the company of the NYSE corporate governance listing standards as of the date of the certification, qualifying the certification to the extent necessary. The Chief Executive Officer of our general partner provided such certification to the NYSE in 2013 without qualification.
Section 16(a) Beneficial Ownership Reporting Compliance
Pursuant to Section 16(a) of the Exchange Act, our officers and directors, and persons beneficially owning more than 10% of our units, are required to file with the SEC reports of their initial ownership and changes in ownership of
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our units. Our officers and directors, and persons beneficially owning more than 10% of our units are also required by SEC regulations to furnish us with copies of all Section 16(a) forms they file. Based solely on a review of Forms 3, 4 and 5 furnished to us and written representations from reporting persons that no other reports were required for those persons, we believe that during 2013, all officers and directors, and persons beneficially owning more than 10% of our units who were required to file reports under Section 16(a), complied with such requirements on a timely basis, except as described below. The reports filed in connection with the 2013 phantom unit grants to directors were not timely filed for David L. Griffis, Gregory C. King, Randall J. Larson and D. Mark Leland. These four reports on Form 4 were due on May 15, 2013, but were not filed until May 29, 2013. In accordance with Rule 16a-6 under the Exchange Act, Brian C. Brantley filed a Form 5 on February 10, 2014 to report additional shares acquired in connection with the reinvestment of distributions. However, one transaction reported on this form occurred in 2012 and was due to be filed on a Form 5 by February 14, 2013.
Item 11. Executive Compensation
Compensation Discussion and Analysis
Introduction
We do not directly employ any of the persons responsible for managing our business. We are managed by our general partner, OTLP GP, LLC. Our general partner has the sole responsibility for conducting our business and for managing our operations, and its board of directors and officers make decisions on our behalf. The officers of our general partner, which we refer to as our officers, are employed by OTNA, and manage the day-to-day affairs of our business. We do not incur any direct compensation charge for the executive officers of our general partner. Instead, under the Services Agreement, we pay OTNA an annual administrative fee, which is intended to compensate OTNA for providing certain corporate staff and support services to us, including services provided to us by the executive officers of our general partner. The administrative fee is a lump-sum payment and does not reflect specific amounts attributable to the compensation of executive officers of our general partner while acting on our behalf.
Compensation Setting Process
Historically, the managing director of Oiltanking GmbH, the parent of OTA, has determined the overall compensation philosophy and set the final compensation of the officers of OTA and its subsidiaries without the assistance of a compensation consultant. OTA’s executive officers have traditionally been compensated with base salary and annual cash bonuses. Base salary amounts were historically determined in the sole discretion of Oiltanking GmbH, and annual cash bonuses were determined based on a percentage of the annual profit of our Houston and Beaumont operations. In the future, we expect that OTA will grant annual bonuses, the amounts of which may be determined based on a variety of factors that could include the financial and operational performance of our operations, the financial and operational performance of Oiltanking GmbH’s operations and the achievement of individual performance goals.
After our IPO, the compensation of the executive officers of our general partner continues to be established by OTA and Oiltanking GmbH. Accordingly, the board of directors of our general partner does not play any role in setting the compensation of the executive officers of our general partner, and we do not have any employment agreements with these officers. Ultimately, all compensation decisions are made at the discretion of the managing director of Oiltanking GmbH. Moreover, as permitted by the NYSE’s rules applicable to publicly traded partnerships, we do not have a compensation committee.
In connection with our IPO, Oiltanking GmbH, in consultation with Towers Watson, an independent compensation consultant, considered the compensation structures and levels that it believed would be necessary for executive recruitment and retention as a public company. OTA and Oiltanking GmbH also examine the compensation practices of our peer companies and data from the storage and terminaling industry, on a periodic basis, to ensure competitive compensation opportunities are provided to OTA’s executive officers.
Long-Term Incentive Plan
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In connection with our IPO, the board of directors of our general partner adopted the Oiltanking Partners, L.P. Long-Term Incentive Plan (“LTIP”), for employees, consultants and directors who perform services for us. The LTIP provides for awards of restricted units, unit options, phantom units, unit payments, unit appreciation rights, other equity-based awards, distribution equivalent rights and performance awards. The LTIP limits the number of units that may be delivered pursuant to awards to 3,889,980 common units, which was 10% of the outstanding common units and subordinated units at our IPO. Common units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The LTIP will expire on July 13, 2021, which is the tenth anniversary of its approval, when common units are no longer available under the LTIP for grants or upon its termination by the plan administrator, whichever occurs first.
As of December 31, 2013, no awards had been granted under the LTIP, and we do not expect to grant any awards in the future. Rather, we expect that OTA will continue to grant equity-based awards pursuant to a separate equity-based award program that OTA administers.
Deferred Compensation Plan
Our executive officers are eligible to participate in the Oiltanking Holding Americas, Inc. Deferred Compensation Plan (the “Deferred Plan”). The Deferred Plan is an unfunded retirement plan intended to supplement the retirement needs of a select group of management employees that are subject to compensation and contribution limitations in the Internal Revenue Code of 1986, as amended (the “Code”) with respect to other qualified retirement vehicles.
The Deferred Plan defines “compensation” as the aggregate amount of compensation payable to a participant for a plan year, including salary, overtime, commissions, bonuses and all other items that constitute “wages” within the meaning of Section 3401(a) of the Code. Participants may elect to defer a dollar amount or a percentage of compensation that the individual is entitled to receive during any calendar year by making salary deferral elections and/or bonus deferral elections. In order to comply with certain requirements of Section 409A of the Code, the participant’s election to defer either salary or bonus amounts must be made in the year prior to the year in which that compensation will be earned. Salary deferrals are limited to 90% of a participant’s salary while bonus deferrals may relate to 100% of a participant’s potential bonus for the upcoming year. A participant will be 100% vested at all times in each salary and/or bonus deferral amounts.
At the time that a participant makes a salary deferral election, the participant may also choose to make one or more of the following elections in the same manner as his or her salary deferral election: a FICA excess deferral election, a 401(k) refund offset election and a 401(k) excess deferral election. A FICA excess deferral election allows the participant to defer an amount equal to the participant’s portion of the FICA tax rate on compensation (excluding bonuses) in excess of the Deferred Plan’s social security wage base. The 401(k) refund offset election would be equal to the amount the participant is due, if any, with respect to the result of the nondiscrimination testing results of our 401(k) plan. The 401(k) excess deferral election means the amount that the participant is prohibited from contributing to our 401(k) plan as a result of the limitations under Section 402(g) of the Code. These deferrals will be considered part of the participant’s salary deferral election and will be subject to a maximum deferral percentage of 90% as well.
OTA has the discretion, but not the obligation, to make employer contributions into the Deferred Plan on a participant’s behalf from time to time, and such contributions may be subject to any restrictions that OTA feels are appropriate, such as vesting restrictions.
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Compensation Committee Report
Our general partner’s board of directors has reviewed and discussed with management the compensation discussion and analysis disclosure contained in this Report as required by Item 402(b) of Regulation S-K. Based on those reviews and discussions, the board of directors has recommended that the compensation discussion and analysis be included in the Annual Report on Form 10-K for the year ended December 31, 2013 for filing with the SEC.
Anne-Marie Ainsworth
Carlin G. Conner
David L. Griffis
James Flannan Browne
Gregory C. King
Randall J. Larson
D. Mark Leland
Director Compensation
The officers or employees of our general partner, OTA or OTA’s affiliates who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not officers or employees of our general partner, OTA or OTA’s affiliates receive compensation as set by our general partner’s board of directors. For 2013, each non-employee director received a compensation package that consisted of: (i) an annual retainer of $47,250; (ii) an additional retainer of $5,250 for the chairperson of each committee of the board of directors; (iii) a meeting attendance payment of $2,100 per in-person board of directors and committee meeting, and (iv) a meeting attendance payment of $1,575 per telephonic board of directors and committee meeting. Non-employee directors are also reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees. In addition, each non-employee director received a grant of 1,000 phantom units on May 13, 2013 under the equity-based award program administered by OTA. Each phantom unit is the economic equivalent of one common unit in the partnership. One hundred percent of the phantom units vested on December 15, 2013, and they were settled through a cash payment equal the number of phantom units held on the vesting date, multiplied by the fair market value of our common units on such date, as computed in accordance with the award agreement, the form of which is filed as an exhibit to this Report. Upon vesting of the phantom units, each non-employee director received a cash payment in the amount of $58,259.
Effective January 1, 2014, the director compensation package was increased as follows: (i) the annual retainer was increased to $55,000; (ii) the additional retainer for the chairperson of each committee of the board of directors was increased to $10,000; (iii) the meeting attendance payment for in-person board of directors and committee meetings was unchanged remaining at $2,100; and (iv) the meeting attendance payment for telephonic board of directors and committee meetings was unchanged remaining at $1,575. It is also anticipated that each non-employee director will receive a grant under the equity-based award program administered by OTA of 1,500 phantom units for their service during the 2014 fiscal year.
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The following table provides information concerning the compensation of our general partner’s directors for the year ended December 31, 2013:
Director Compensation Table for 2013
Name | Fees earned or paid in cash ($) | Unit awards ($) (1) | All other compensation ($) | Total ($) | ||||||||
Carlin G. Conner (2) | — | — | — | — | ||||||||
Anne-Marie Ainsworth (2) | — | — | — | — | ||||||||
James Flannan Browne (2) | — | — | — | — | ||||||||
David L. Griffis | 66,150 | 58,259 | — | 124,409 | ||||||||
Gregory C. King | 71,400 | 58,259 | — | 129,659 | ||||||||
Randall J. Larson (3) | 69,825 | 58,259 | — | 128,084 | ||||||||
D. Mark Leland | 64,575 | 58,259 | — | 122,834 | ||||||||
________________
(1) | At December 31, 2013, none of the directors held any outstanding equity awards. The values shown in this column reflect the fair value of the phantom awards granted to the non-employee directors in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718. Each of Mr. Griffis, Mr. King, Mr. Larson and Mr. Leland was granted 1,000 phantom units on May 13, 2013. The phantom units vested on December 15, 2013 and were settled based upon the fair market value of a common unit on that date, providing a cash payment of $58,259 to each non-employee director. |
(2) | Because Mr. Conner, Ms. Ainsworth and Mr. Browne are employees of an affiliate of our general partner, they do not receive any compensation for service as a director of our general partner. |
(3) | Mr. Larson resigned from the board of directors on February 19, 2014. |
Compensation Committee Interlocks and Insider Participation
Our general partner’s board of directors performs the function of a compensation committee. Ms. Ainsworth is a director and executive officer of our general partner, and Mr. Conner is the chairman of the board of our general partner and was formerly an executive officer of our general partner. Mr. Browne serves as the Head of Legal and Insurance for Oiltanking GmbH. Mr. Griffis is employed by and a shareholder of the law firm of Crain, Caton & James, P.C., a firm that provides legal counsel to us, as well as to OTA and certain of its other affiliates. Fees for legal services paid to Crain, Caton & James, P.C. for services provided to us totaled $1.2 million, $1.1 million and $0.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth certain information, as of February 20, 2014, concerning the beneficial ownership of our units by each person known by us to own more than 5% of the outstanding units, by each director and named executive officer of our general partner, and by all directors and executive officers of our general partner as a group. The number of units in the table below includes units issuable upon the exercise of outstanding equity grants to the extent that such grants are exercisable by the respective directors, named executive officers and the executive officers, as the case may be, on or within 60 days after February 20, 2014. All information with respect to beneficial ownership is based solely upon information furnished by the respective directors, named executive officers and executive officers, as the case may be, or information contained in filings made by such beneficial owners with the SEC. The address for the individuals and entities for which an address is not otherwise indicated is: c/o Oiltanking Partners, L.P., 333 Clay Street, Suite 2400, Houston, TX 77002.
Name of Beneficial Owner (1) | Common Units Beneficially Owned | Percentage of Common Units Beneficially Owned | Subordinated Units Beneficially Owned | Percentage of Subordinated Units Beneficially Owned | Percentage of Common and Subordinated Units Beneficially Owned | |||||||
OTA (2) | 7,949,901 | 36.1% | 19,449,901 | 100.0% | 66.0% | |||||||
Chickasaw Capital Management, LLC (3) | 1,495,237 | 6.8% | — | — | 3.6% | |||||||
Goldman Sachs Asset Management (4) | 2,221,033 | 10.1% | — | — | 5.4% | |||||||
Tortoise Capital Advisors, L.L.C. (5) | 2,514,096 | 11.4% | — | — | 6.1% | |||||||
Anne-Marie Ainsworth | 13,000 | * | — | — | * | |||||||
Jonathan Z. Ackerman (6) | — | * | — | — | * | |||||||
Kenneth F. Owen (7) | N/A | * | — | — | * | |||||||
Robert J. “Bo” McCall | 3,000 | * | — | — | * | |||||||
Brian C. Brantley | 571 | * | — | — | * | |||||||
Kevin L. Campbell | 100 | * | — | — | * | |||||||
Clayton K. Curtis | 7,500 | * | — | — | * | |||||||
Javier Del Olmo B. | 700 | * | — | — | * | |||||||
Kim M. Ivy | — | * | — | — | * | |||||||
Carlin G. Conner (8) | 12,000 | * | — | — | * | |||||||
James Flannan Browne | — | * | — | — | * | |||||||
David L. Griffis (9) | 9,288 | * | — | — | * | |||||||
Thomas M. Hart III | — | * | — | — | * | |||||||
Gregory C. King | 10,000 | * | — | — | * | |||||||
D. Mark Leland | 8,690 | * | — | — | * | |||||||
All executive officers and directors as a group (14 persons) | 64,849 | * | — | — | * | |||||||
________________________
* | Less than 1.0%. |
(1) | There are no arrangements for any listed beneficial owner to acquire within 60 days common units from options, warrants, rights, conversion privileges or similar obligations. |
(2) | Includes 4,368,869 common units and 8,992,059 subordinated units held directly by OTB Holdco, L.L.C., a wholly owned subsidiary of OTA. OTA is a wholly owned subsidiary of Oiltanking GmbH, which, in turn, is a wholly owned subsidiary of Marquard & Bahls AG, which is controlled by a four-person supervisory board. Excludes the 2.0% general partner interest and related IDRs held by our general partner, which are not considered “units” for purposes of our limited partnership agreement. The general partner, accordingly, is not considered a “unitholder.” |
(3) | Based upon the Schedule 13G/A filed on January 24, 2014 with the SEC with respect to our common units held as of December 31, 2013, Chickasaw Capital Management, LLC has sole voting and dispositive power |
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as to 1,495,237 common units. The address for Chickasaw Capital Management, LLC is 6075 Poplar Ave., Suite 4020, Memphis, TN 38119.
(4) | Based upon the Schedule 13G/A filed on February 10, 2014 with the SEC with respect to our common units held as of December 31, 2013, Goldman Sachs Asset Management, L.P., together with GS Investment Strategies, LLC (collectively, “Goldman Sachs Asset Management”) had shared voting and dispositive power as to 1,964,016 common units. Subsequently on February 10, 2014, Goldman Sachs Asset Management filed another Schedule 13G/A with respect to our common units held as of January 31, 2014, reporting that it has shared voting and dispositive power as to 2,221,033 common units. The address for Goldman Sachs Asset Management is 200 West Street, New York, NY 10282. |
(5) | Based upon the Schedule 13G filed on February 11, 2014 with the SEC with respect to our common units held as of December 31, 2013, Tortoise Capital Advisors, L.L.C. (“TCA”) has shared voting power as to 2,269,237 common units and shared dispositive power as to 2,514,096 common units. TCA, by virtue of investment advisory agreements with certain investment companies to which it acts as an investment advisor, has all investment and voting power over securities owned of record by these investment companies. TCA also acts as an investment advisor to certain managed accounts. Under contractual agreements with individual account holders, TCA, with respect to the securities held in the managed accounts, shares investment and voting power with certain account holders, and has no voting power but shares investment power with certain other account holders. The address for TCA is 11550 Ash Street, Suite 300, Leawood, Kansas 66211. |
(6) | Mr. Ackerman has entered into a unit purchase plan in compliance with Rule 10b5-1 under the Exchange Act, pursuant to which the first purchase is anticipated to occur within sixty days of the filing of this Report. |
(7) | Effective July 1, 2013, Mr. Owen left his position as the Chief Financial Officer of the general partner, and became the Terminal Manager at our Houston facility. As a result, Mr. Owen is no longer a “named executive officer,” and he is no longer required to file beneficial ownership reports pursuant to Section 16 of the Exchange Act. |
(8) | On February 18, 2014, we announced that Mr. Connor notified us of his intention to resign from his positions with the Oiltanking Group and our general partner. We expect that Mr. Conner will continue in his current roles until a successor is appointed. |
(9) | The amount of common units beneficially owned by Mr. Griffis does not include 1,655 common units that are beneficially owned by Mr. Griffis’s daughter. Mr. Griffis is deemed to have shared voting and investment power over these common units because he has trading authority with respect to his daughter’s brokerage account; however, he has no direct or indirect pecuniary interest in these common units. |
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Equity Compensation Plan Information
The following table sets forth information as of December 31, 2013 with respect to compensation plans under which our equity securities are authorized for issuance. For more information regarding the long-term incentive plan, please see “Item 11. Executive Compensation — Compensation Discussion and Analysis — Long-Term Incentive Plan.”
Plan Category | (a) Number of Units to be Issued Upon Exercise of Outstanding Unit Options and Rights | (b) Weighted Average Exercise Price of Outstanding Unit Options and Rights | (c) Number of Units Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) | |||||
Equity compensation plans approved by unitholders: | ||||||||
N/A | — | — | — | |||||
Equity compensation plans not approved by unitholders: | ||||||||
Long-Term Incentive Plan | — | — | 3,889,980 | |||||
Total for equity compensation plans | — | — | 3,889,980 | |||||
____________________
(1) | The Oiltanking Partners, L.P. Long-Term Incentive Plan was adopted by our general partner in July 2011 in connection with our IPO. The LTIP contemplates the issuance or delivery of up to 3,889,980 common units to satisfy awards under the plan. As of December 31, 2013, no awards had been granted under the long-term incentive plan, and we do not expect to grant any awards in the future. Rather, we expect that OTA will continue to grant equity-based awards pursuant to a separate equity-based award program that OTA administers. |
Item 13. Certain Relationships and Related Transactions, and Director Independence
OTA owns, directly or indirectly, 7,949,901 common units and 19,449,901 subordinated units representing an approximate 64.7% limited partner interest in us, and owns and controls our general partner. OTA also appoints all of the directors of our general partner, which maintains a 2.0% general partner interest in us and indirectly owns all of our IDRs.
The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.
Distributions and Payments to Our General Partner and Its Affiliates
The following discussion summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our ongoing operation and any liquidation.
Operational Stage
Distributions of available cash to our general partner and its affiliates. We generally make cash distributions 98.0% to our unitholders, including affiliates of our general partner, as the holders of an aggregate of 22,049,901 common units and 19,449,901 subordinated units, and 2.0% to our general partner. In addition, if distributions exceed the MQD and other higher target distribution levels, our general partner is entitled to increasing percentages of the
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distributions, up to a maximum of 48.0% of the distributions above the highest target distribution level. Assuming we have sufficient available cash to pay the full MQD on all of our outstanding common units and subordinated units for four quarters, our general partner and its affiliates will receive an annual distribution of at least $1.1 million on the 2.0% general partner interest and approximately $37.0 million on their common units and subordinated units.
Payments to our general partner and its affiliates. Our general partner does not receive a management fee or other compensation for its management of our partnership, but we reimburse our general partner and its affiliates pursuant to the Services Agreement. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us but does not limit the amount of expenses for which our general partner and its affiliates will be compensated. Under the Services Agreement, we have an agreed upon fixed fee associated with certain specified selling, general and administrative services necessary to run our business that are provided to us by OTA. These expenses include expenses of non-executive employees, including general and administrative overhead costs, salary, bonus, incentive compensation and other compensation amounts and executive officer expenses, including general and administrative overhead costs, salary, bonus, incentive compensation and other compensation amounts.
Withdrawal or removal of our general partner. If our general partner withdraws or is removed, its general partner interest and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
Agreements with Affiliates
We have entered into certain agreements with OTA, as described in more detail below.
Services Agreement
We have entered into a Services Agreement with our general partner and OTNA, a subsidiary of OTA, pursuant to which OTNA provides us certain specified selling, general and administrative services necessary to manage our business for an annual fixed fee, payable in equal monthly installments. We also reimburse OTNA for all operating expenses and certain other expenses it incurs as a result of our being a publicly traded partnership, including all operating expenses it incurs with respect to insurance coverage for our business, with such reimbursement obligations not subject to any cap.
The annual fixed fee related to selling, general and administrative expenses is adjusted as necessary each year to account for inflation as measured by the consumer price index. In addition, with the approval of the Conflicts Committee of the board of directors of our general partner, the fee may be adjusted to account for growth in our business or asset base. In January 2013, the annual fixed fee was increased from $14.9 million to $15.1 million as a result of an increase in the consumer price index. In August 2013, the Conflicts Committee of the board of directors of our general partner approved a requested increase to the fixed fee charged to us under the Services Agreement to $18.8 million on an annualized basis to reflect higher selling, general and administrative expenses associated with expansion projects placed in service in 2013. The fee increase was effective as of July 1, 2013.
During the year ended December 31, 2013, we paid OTNA a total of $31.4 million pursuant to the Services Agreement, which included payments related to the annual fixed fee and the reimbursement of operating and certain other expenses.
Tax Sharing Agreement
In connection with our IPO, we entered into a tax sharing agreement with OTA pursuant to which we reimburse OTA for our share of state and local income and other taxes borne by OTA as a result of our results being included in
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a combined or consolidated tax return filed by OTA with respect to taxable periods including or beginning on the closing date of our IPO. The amount of any such reimbursement is limited to the tax that we (and our subsidiaries) would have paid had we not been included in a combined group with OTA. OTA may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe no tax. However, we will nevertheless reimburse OTA for the tax we would have owed had the attributes not been available or used for our benefit, even though OTA had no cash expense for that period.
Other Transactions with Related Persons
Revenues Derived from Affiliates
We have engaged in certain transactions with other OTA subsidiaries, as well as other companies related to us by common ownership. Ongoing transactions include our provision of storage and ancillary services at market rates to Matrix Marine Fuels, L.L.C., an indirect, wholly owned subsidiary of our ultimate foreign parent, Marquard & Bahls AG. Amounts charged for storage and ancillary services are classified as revenues.
Total revenues for related party services were as follows for the periods indicated (in thousands):
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Storage and ancillary service fees | $ | 3,317 | $ | 3,212 | $ | 3,142 | |||||
Other revenues | — | 13 | 1,565 | ||||||||
Total related party revenues | $ | 3,317 | $ | 3,225 | $ | 4,707 | |||||
Fees Paid to Affiliates
The following table summarizes related party operating expenses and selling, general and administrative expenses that are reflected in the consolidated statements of income for the periods indicated (in thousands):
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Operating | $ | 15,129 | $ | 12,997 | $ | 4,795 | |||||
Selling, general and administrative | 17,908 | 15,952 | 10,622 | ||||||||
Charges for certain operating and selling, general and administrative services necessary to operate our business that are provided by OTA pursuant to the Services Agreement are included in operating and selling, general and administrative expenses in the table above.
We also pay annual maintenance and technical support costs for proprietary software owned by Oiltanking GmbH, which we use in performing terminaling services for our customers. Each terminal location is allocated a portion of the global Oiltanking GmbH maintenance costs based on the number of users located at each facility. In management’s estimation, the costs incurred approximate the amounts that would have been incurred for similar third-party software programs for terminaling operations. These services are provided pursuant to the Services Agreement.
During the years ended December 31, 2013, 2012 and 2011, we capitalized $5.5 million, $4.3 million and $0.9 million, respectively, of related party engineering services into construction in progress.
Investments with Affiliates
From time to time, we invest cash with OT Finance in short-term notes receivable at then-prevailing market rates. At December 31, 2013, we had short-term notes receivable of $100.0 million from OT Finance, bearing a weighted-average interest rate of 0.23%.
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Potential OTA Financial Support
OTA and other members of the Oiltanking Group, including OT Finance, may elect, but are not obligated, to provide financial support to us under certain circumstances, such as in connection with an acquisition or expansion capital project. Our partnership agreement contains provisions designed to facilitate the Oiltanking Group’s ability to provide us with financial support while reducing concerns regarding conflicts of interest by defining certain potential financing transactions between OTA and other members of the Oiltanking Group, including OT Finance, on the one hand, and us, on the other hand, as fair to our unitholders. In that regard, the following forms of potential Oiltanking Group financial support do not require approval by the Conflicts Committee of the board of directors of our general partner and will be deemed fair to our unitholders, and will not constitute a breach of any fiduciary or other duty owed to us by our general partner, if consummated on terms no less favorable than described below:
• | our issuance of common units to OTA or any of its affiliates at a price per common unit of no less than 95% of the trailing 10-day average closing price per common unit; |
• | our borrowing of funds from OTA or any of its affiliates on terms that include a term of at least one year and no more than ten years and a fixed rate of interest that is no more than 200 basis points higher than the corresponding base rate, which is LIBOR for one year maturities and the USD swap rate for maturities of greater than one year and up to ten years; and |
• | OTA and its affiliates may provide us with guaranties or trade credit support to support our ongoing operations; provided, that (i) the pricing of any such guaranties or trade credit support is no more than 100 basis points per annum and (ii) any such guaranties or trade credit support are limited to our ordinary course obligations and do not extend to indebtedness for borrowed money or other obligations that could be characterized as debt. |
We have no obligation to seek financing or support from OTA or any other member of the Oiltanking Group on the terms described above or to accept such financing or support if it is offered to us. In addition, neither OTA nor any other member of the Oiltanking Group has any obligation to provide financial support under these or any other circumstances. The existence of these provisions will not preclude other forms of financial support from OTA or any other member of the Oiltanking Group, including financial support on significantly less favorable terms under circumstances in which such support appears to be in our best interests.
In addition, following the completion of our issuance of units in connection with an underwritten public offering, direct placement and/or private offering of units, we may make a reasonably prompt redemption of a number of common units owned by OTA or its affiliates that is no greater than the aggregate number of common units issued to OTA or its affiliates pursuant to the provisions summarized in the first bullet above (taking into account any prior redemption pursuant to the provisions summarized in this paragraph) at a price per common unit that is no greater than the price per common unit paid by the investors in such offering, as applicable, less underwriting discounts and commissions or placement fees, if any. As with the transactions described in the bullets above, any such redemption will be deemed fair to our unitholders and will not constitute a breach of any duty owed to us by our general partner.
Long-Term Debt, Affiliate
During 2003, the Oiltanking Group enacted a policy of centrally financing the expansion and growth of their global holdings of terminaling subsidiaries, and in 2008 established OT Finance, a wholly owned finance company of Oiltanking GmbH located in Amsterdam, The Netherlands. OT Finance serves as the global financing division for the Oiltanking Group’s terminal holdings, including us, and arranges loans and notes at market rates and terms for approved terminal construction projects. We believe that this relationship has historically provided us with access to debt capital on terms that are consistent with or better than what would have been available to us from third parties. We believe this relationship could continue to provide us with access to capital at competitive rates.
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At December 31, 2013, we had $190.8 million of outstanding debt payable to OT Finance. Total required debt principal repayments for each of the years in the period ending December 31, 2018 and thereafter are as follows (in thousands):
Amount | |||
2014 | $ | 2,500 | |
2015 | 2,500 | ||
2016 | 2,500 | ||
2017 | 2,500 | ||
2018 | 2,500 | ||
Thereafter | 178,300 | ||
Total | $ | 190,800 | |
At December 31, 2013, our covenants restrict us from declaring distributions in excess of $316.2 million on an annual basis.
For further information regarding our debt agreements with OT Finance, see Note 8 in the Notes to Consolidated Financial Statements.
Transactions with a Certain Director
One of the directors of our general partner, David L. Griffis, is employed by and a shareholder of the law firm of Crain, Caton & James, P.C., a firm that provides legal counsel to us, as well as to OTA and certain of its other affiliates. Fees for legal services paid to Crain, Caton & James, P.C. for services provided to us totaled $1.2 million, $1.1 million and $0.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Procedures for Review, Approval and Ratification of Transactions with Related Persons
The board of directors has adopted a written Code of Conduct, under which all directors and officers of the general partner and employees working on our behalf are expected to avoid conflicts of interest, including perceived conflicts of interest, in relation to their duties and responsibilities to us, and promptly report any violations of the Code of Conduct by any person. Directors are expected to bring to the attention of the chief executive officer or the board of directors any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board of directors in light of the circumstances, be determined by a majority of the disinterested directors. Similarly, executive officers are required to avoid conflicts of interest unless approved by the board of directors.
If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors or the conflicts committee in accordance with the provisions of our partnership agreement. At the discretion of the board of directors in light of the circumstances, the resolution may be determined by the board of directors in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.
The Code of Conduct described above was adopted in connection with the closing of our IPO, and as a result, the transactions described above which were entered into prior to our IPO, were not reviewed according to the foregoing procedures.
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Item 14. Principal Accounting Fees and Services
We have engaged BDO USA, LLP as our independent registered public accounting firm and principal accountants. The aggregate fees for professional services rendered by our principal accountants, BDO USA, LLP, were as follows for the periods indicated (in thousands):
Year Ended December 31, | |||||||
2013 | 2012 | ||||||
Audit Fees (1) | $ | 543 | $ | 609 | |||
Audit-Related Fees (2) | — | — | |||||
Tax Fees (3) | — | — | |||||
All Other Fees (4) | — | — | |||||
Total | $ | 543 | $ | 609 | |||
_________________
(1) | Audit fees represent fees for professional services rendered in connection with (i) the audit of our annual financial statements, (ii) the review of our quarterly financial statements and (iii) those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. This information is presented as of the latest practicable date for this Report. |
(2) | Audit-related fees represent fees for assurance and related services. |
(3) | Tax fees represent fees for professional services rendered in connection with tax compliance. |
(4) | All other fees represent fees for services not classifiable under the other categories listed in the table above. |
Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accountant
As outlined in its charter, the Audit Committee of the board of directors of our general partner is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent auditors. BDO USA, LLP’s engagement to conduct our 2013 and 2012 audits and quarterly reviews post-IPO were pre-approved by the Audit Committee.
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PART IV
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as a part of this Report:
(1) | Financial Statements — see Index to Consolidated Financial Statements. |
(2) | Financial Statement Schedules — None. |
(3) | Exhibits, including those incorporated by reference. The following is a list of exhibits filed as part of this Report. |
Exhibit Number | Description |
3.1 | Certificate of Limited Partnership of Oiltanking Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-173199) filed on March 31, 2011). |
3.2 | First Amended and Restated Agreement of Limited Partnership of Oiltanking Partners, L.P. dated July 19, 2011 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
3.3 | Certificate of Formation of OTLP GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (File No. 333-173199) filed on March 31, 2011). |
3.4 | Amended and Restated Limited Liability Company Agreement of OTLP GP, LLC, dated July 19, 2011 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
10.1 | Contribution, Conveyance and Assumption Agreement by and among Oiltanking Partners, L.P., OTLP GP, LLC, Oiltanking Holding Americas, Inc., OTB Holdco, LLC, Oiltanking Beaumont GP, L.L.C., Oiltanking Beaumont Partners, L.P., OTB GP, LLC, Oiltanking Houston, L.P. and OTH GP, LLC dated July 19, 2011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
10.2 | Omnibus Agreement by and among Oiltanking Partners, L.P., OTLP GP, LLC and Oiltanking Holding Americas, Inc., dated July 19, 2011 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
10.3 | Tax Sharing Agreement by and between Oiltanking Partners, L.P. and Oiltanking Holding Americas, Inc., dated as of July 19, 2011 (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
10.4† | Oiltanking Partners, L.P. Long-Term Incentive Plan, adopted as of July 19, 2011 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
10.5 | Services Agreement by and among Oiltanking Partners, L.P., OTLP GP, LLC, Oiltanking North America, LLC and Oiltanking Beaumont Specialty Products, LLC, dated July 19, 2011 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
10.6 | First Amendment to Services Agreement by and among Oiltanking Partners, L.P., OTLP GP, LLC, Oiltanking North America, LLC and Oiltanking Beaumont Specialty Products, LLC, dated December 31, 2011, but effective July 19, 2011 (incorporated by reference to Exhibit 10.7 to the Annual Report on Form 10-K (File No. 001-35230) filed on March 14, 2012). |
10.7 | Second Amendment to Services Agreement by and among Oiltanking Partners, L.P., OTLP GP, LLC, Oiltanking North America, LLC and Oiltanking Beaumont Specialty Products, LLC, dated August 5, 2013, effective July 1, 2013 (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q (File No. 001-35230) filed on August 7, 2013). |
10.8 | Credit Agreement by and between Oiltanking Partners, L.P. as Borrower and Oiltanking Finance B.V. as Lender, dated as of June 15, 2011, as amended by Addendum No. 1 thereto, dated June 22, 2011 (incorporated herein by reference to Exhibit 10.6 to the Registration Statement on Form S-1/A (File No. 333-173199), filed on June 23, 2011). |
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10.9 | Addendum No. 2 dated November 7, 2012, to the Credit Limit Agreement dated June 15, 2011, between Oiltanking Partners, L.P. as Borrower, and Oiltanking Finance B.V. as Lender (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012 (File No. 001-35320) filed on November 7, 2012). |
10.10 | Loan Agreement by and between Oiltanking Houston, L.P. as Borrower and Oiltanking Finance B.V. as Lender, dated as of May 16, 2012, but effective as of May 11, 2012 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35230) filed on May 21, 2012). |
10.11 | Loan Agreement by and between Oiltanking Houston, L.P. as Borrower and Oiltanking Finance B.V. as Lender, effective as of May 31, 2013 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35230) filed on June 26, 2013). |
10.12† | Form of Phantom Unit Award Agreement for Consultants and Directors under the Oiltanking North America, LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013 (File No. 001-35320) filed on August 7, 2013). |
*21.1 | List of Subsidiaries of Oiltanking Partners, L.P. |
*23.1 | Consent of BDO USA, LLP. |
*31.1 | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. |
*31.2 | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. |
**32.1 | Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350. |
**32.2 | Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350. |
*101.INS | XBRL Instance Document. |
*101.SCH | XBRL Taxonomy Extension Schema Document. |
*101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document. |
*101.DEF | XBRL Taxonomy Extension Definition Linkbase Document. |
*101.LAB | XBRL Taxonomy Extension Label Linkbase Document. |
*101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document. |
_____________
† | Represents management contract or compensatory plan or arrangement. |
* | Filed herewith. |
** | Furnished herewith. |
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SIGNATURES
Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
By: | OILTANKING PARTNERS, L.P. (Registrant) | ||
By: | OTLP GP, LLC, as General Partner | ||
Date: | February 24, 2014 | By: | /s/ ANNE-MARIE AINSWORTH |
Anne-Marie Ainsworth President and Chief Executive Officer and Director (Duly Authorized Officer) | |||
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date: | February 24, 2014 | By: | /s/ ANNE-MARIE AINSWORTH |
Anne-Marie Ainsworth President and Chief Executive Officer and Director (Principal Executive Officer) | |||
Date: | February 24, 2014 | By: | /s/ CARLIN G. CONNER |
Carlin G. Conner Chairman of the Board | |||
Date: | February 24, 2014 | By: | /s/ JONATHAN Z. ACKERMAN |
Jonathan Z. Ackerman Vice President & Chief Financial Officer (Principal Financial Officer) | |||
Date: | February 24, 2014 | By: | /s/ DONNA Y. HYMEL |
Donna Y. Hymel Controller (Principal Accounting Officer) | |||
Date: | February 24, 2014 | By: | /s/ JAMES FLANNAN BROWNE |
James Flannan Browne Director | |||
Date: | February 24, 2014 | By: | /s/ DAVID L. GRIFFIS |
David L. Griffis Director | |||
Date: | February 24, 2014 | By: | /s/ GREGORY C. KING |
Gregory C. King Director | |||
Date: | February 24, 2014 | By: | /s/ D. MARK LELAND |
D. Mark Leland Director | |||
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Exhibit Index
Exhibit Number | Description |
3.1 | Certificate of Limited Partnership of Oiltanking Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-173199) filed on March 31, 2011). |
3.2 | First Amended and Restated Agreement of Limited Partnership of Oiltanking Partners, L.P. dated July 19, 2011 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
3.3 | Certificate of Formation of OTLP GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (File No. 333-173199) filed on March 31, 2011). |
3.4 | Amended and Restated Limited Liability Company Agreement of OTLP GP, LLC, dated July 19, 2011 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
10.1 | Contribution, Conveyance and Assumption Agreement by and among Oiltanking Partners, L.P., OTLP GP, LLC, Oiltanking Holding Americas, Inc., OTB Holdco, LLC, Oiltanking Beaumont GP, L.L.C., Oiltanking Beaumont Partners, L.P., OTB GP, LLC, Oiltanking Houston, L.P. and OTH GP, LLC dated July 19, 2011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
10.2 | Omnibus Agreement by and among Oiltanking Partners, L.P., OTLP GP, LLC and Oiltanking Holding Americas, Inc., dated July 19, 2011 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
10.3 | Tax Sharing Agreement by and between Oiltanking Partners, L.P. and Oiltanking Holding Americas, Inc., dated as of July 19, 2011 (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
10.4† | Oiltanking Partners, L.P. Long-Term Incentive Plan, adopted as of July 19, 2011 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
10.5 | Services Agreement by and among Oiltanking Partners, L.P., OTLP GP, LLC, Oiltanking North America, LLC and Oiltanking Beaumont Specialty Products, LLC, dated July 19, 2011 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-35230) filed on July 19, 2011). |
10.6 | First Amendment to Services Agreement by and among Oiltanking Partners, L.P., OTLP GP, LLC, Oiltanking North America, LLC and Oiltanking Beaumont Specialty Products, LLC, dated December 31, 2011, but effective July 19, 2011 (incorporated by reference to Exhibit 10.7 to the Annual Report on Form 10-K (File No. 001-35230) filed on March 14, 2012). |
10.7 | Second Amendment to Services Agreement by and among Oiltanking Partners, L.P., OTLP GP, LLC, Oiltanking North America, LLC and Oiltanking Beaumont Specialty Products, LLC, dated August 5, 2013, effective July 1, 2013 (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q (File No. 001-35230) filed on August 7, 2013). |
10.8 | Credit Agreement by and between Oiltanking Partners, L.P. as Borrower and Oiltanking Finance B.V. as Lender, dated as of June 15, 2011, as amended by Addendum No. 1 thereto, dated June 22, 2011 (incorporated herein by reference to Exhibit 10.6 to the Registration Statement on Form S-1/A (File No. 333-173199), filed on June 23, 2011). |
10.9 | Addendum No. 2 dated November 7, 2012, to the Credit Limit Agreement dated June 15, 2011, between Oiltanking Partners, L.P. as Borrower, and Oiltanking Finance B.V. as Lender (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012 (File No. 001-35320) filed on November 7, 2012). |
10.10 | Loan Agreement by and between Oiltanking Houston, L.P. as Borrower and Oiltanking Finance B.V. as Lender, dated as of May 16, 2012, but effective as of May 11, 2012 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35230) filed on May 21, 2012). |
10.11 | Loan Agreement by and between Oiltanking Houston, L.P. as Borrower and Oiltanking Finance B.V. as Lender, effective as of May 31, 2013 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35230) filed on June 26, 2013). |
112
10.12† | Form of Phantom Unit Award Agreement for Consultants and Directors under the Oiltanking North America, LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013 (File No. 001-35320) filed on August 7, 2013). |
*21.1 | List of Subsidiaries of Oiltanking Partners, L.P. |
*23.1 | Consent of BDO USA, LLP. |
*31.1 | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. |
*31.2 | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. |
**32.1 | Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350. |
**32.2 | Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350. |
*101.INS | XBRL Instance Document. |
*101.SCH | XBRL Taxonomy Extension Schema Document. |
*101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document. |
*101.DEF | XBRL Taxonomy Extension Definition Linkbase Document. |
*101.LAB | XBRL Taxonomy Extension Label Linkbase Document. |
*101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document. |
_____________
† | Represents management contract or compensatory plan or arrangement. |
* | Filed herewith. |
** | Furnished herewith. |
113