UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] 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
[ ] 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 1-35574
EQT Midstream Partners, LP
(Exact name of registrant as specified in its charter)
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DELAWARE (State or other jurisdiction of incorporation or organization)
625 Liberty Avenue Pittsburgh, Pennsylvania (Address of principal executive offices) |
37-1661577 (IRS Employer Identification No.)
15222 (Zip Code) |
Registrant’s telephone number, including area code: (412) 553-5700
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class |
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Name of each exchange on which registered |
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Common Units Representing Limited Partner Interests |
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New York Stock Exchange |
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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 ý 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 ý
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 ý No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 ý 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. ý
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. (Check one):
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Large accelerated filer o |
Accelerated filer ý |
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Non-accelerated filer o |
Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No ý
The aggregate market value of the Common Units held by non-affiliates of the registrant as of June 30, 2013: $692.2 million
At January 31, 2014, there were 30,468,902 Common Units, 17,339,718 Subordinated Units and 975,686 General Partner Units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
Glossary of Commonly Used Terms, Abbreviations and Measurements
adjusted EBITDA – a supplemental non-GAAP financial measure defined by the Partnership as net income plus net interest expense, depreciation and amortization expense, income tax expense (if applicable), non-cash long-term compensation expense and other non-cash adjustments (if applicable) less other income and capital lease payments prior to acquisition of the underlying assets.
AFUDC (Allowance for Funds Used During Construction) – carrying costs for the construction of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. The capitalized amount for construction of regulated assets includes interest cost and a designated cost of equity for financing the construction of these regulated assets.
Appalachian Basin – the area of the United States composed of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie in the Appalachian Mountains.
British thermal unit – a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
distributable cash flow – a supplemental non-GAAP financial measure defined by the Partnership as adjusted EBITDA less net cash interest, ongoing maintenance capital expenditures and potentially reimbursable maintenance capital expenditures plus reimbursable maintenance capital expenditures to be reimbursed by EQT Corporation (EQT).
end-user markets – the ultimate users and consumers of transported energy products.
firm contracts – contracts for transportation services that obligate customers to pay a fixed monthly charge to reserve an agreed upon amount of pipeline capacity regardless of the actual pipeline capacity used by a customer during each month.
gas – all references to “gas” in this report refer to natural gas.
horizontal drilling – drilling that ultimately is horizontal or near horizontal to increase the length of the well bore penetrating the target formation.
local distribution company or LDC – LDCs are companies involved in the delivery of natural gas to consumers within a specific geographic area.
LNG – natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times.
NGA – Natural Gas Act of 1938.
NGPA – Natural Gas Policy Act of 1978.
omnibus agreement – the agreement entered into among the Partnership, its general partner and EQT in connection with the Partnership’s initial public offering, pursuant to which EQT agreed to provide the Partnership with certain general and administrative services and a license to use the name “EQT” and related marks in connection with the Partnership’s business. The omnibus agreement also provides for certain indemnification and reimbursement obligations between the Partnership and EQT.
park and loan services - those services pursuant to which customers receive the right to store natural gas in (park), or borrow gas from (loan), the Partnership’s facilities on a seasonal basis.
PSIA – Pipeline Safety Improvement Act of 2002.
PSCT – Pipeline Safety Cost Tracker
play – a proven geological formation that contains commercial amounts of hydrocarbons.
Glossary of Commonly Used Terms, Abbreviations and Measurements
receipt point – the point where production is received by or into a gathering system or transportation pipeline.
reservoir – a porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.
Sunrise Merger – On July 22, 2013, Sunrise Pipeline, LLC (Sunrise) merged into Equitrans, L.P., a subsidiary of the Partnership.
throughput – the volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.
wellhead – the equipment at the surface of a well used to control the well’s pressure and the point at which the hydrocarbons and water exit the ground.
working gas – the volume of natural gas in the storage reservoir that can be extracted during the normal operation of the storage facility.
Abbreviations
ASC - Accounting Standards Codification
CBM – Coalbed Methane
DOT – U.S. Department of Transportation
FASB – Financial Accounting Standards Board
FERC – Federal Energy Regulatory Commission
GAAP – Generally Accepted Accounting Principles
IRS – Internal Revenue Service
LDC – Local Distribution Company
NYMEX – New York Mercantile Exchange
NYSE – New York Stock Exchange
PA PUC – Pennsylvania Public Utility Commission
PHMSA – Pipeline and Hazardous Materials Safety Administration
SEC – Securities and Exchange Commission
WV PSC – West Virginia Public Service Commission
Measurements
Btu = British thermal unit
BBtu = billion British thermal units
Bcf = billion cubic feet
Dth = million British thermal units
Mcf = thousand cubic feet
MMBtu = million British thermal units
MMcf = million cubic feet
TBtu = trillion British thermal units
Tcf = trillion cubic feet
Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,” “estimate,” “could,” “would,” “will,” “may,” “forecasts,” “approximate,” “expect,” “project,” “intend,” “plan,” “believe” and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report on Form 10-K include the matters discussed in the sections captioned “Strategy” in Item 1, “Business” and “Outlook” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of the Partnership and its subsidiaries, including guidance regarding the Partnership’s transmission and storage and gathering revenue and volume growth; revenue projections; the weighted average contract life of transmission, storage and gathering contracts; infrastructure programs (including the timing, cost, capacity and sources of funding with respect to transmission and gathering expansion projects); natural gas production growth in the Partnership’s operating areas for EQT Corporation and third parties; asset acquisitions, including the Partnership’s ability to complete any asset acquisitions from EQT Corporation or third parties; the amount and timing of distributions, including expected increases; the effect of the AVC lease on distributable cash flow; future projected AVC lease payments; projected operating and capital expenditures, including the amount of capital expenditures reimbursable by EQT Corporation; liquidity and financing requirements, including sources and availability; the effects of government regulation and litigation; and tax position. The forward-looking statements included in this Annual Report on Form 10-K involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The Partnership has based these forward-looking statements on current expectations and assumptions about future events. While the Partnership considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Partnership’s control. The risks and uncertainties that may affect the operations, performance and results of the Partnership’s business and forward-looking statements include, but are not limited to, those set forth under Item 1A, “Risk Factors” and elsewhere in this Annual Report on Form 10-K.
Any forward-looking statement speaks only as of the date on which such statement is made and the Partnership does not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.
In reviewing any agreements incorporated by reference in or filed with this Annual Report on Form 10-K, please remember that such agreements are included to provide information regarding the terms of such agreements and are not intended to provide any other factual or disclosure information about the Partnership. The agreements may contain representations and warranties by the Partnership, which should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to such agreements should those statements prove to be inaccurate. The representations and warranties were made only as of the date of the relevant agreement or such other date or dates as may be specified in such agreement and are subject to more recent developments. Accordingly, these representations and warranties alone may not describe the actual state of affairs of the Partnership or its affiliates as of the date they were made or at any other time.
EQT Midstream Partners, LP (EQT Midstream Partners or the Partnership) closed its initial public offering (IPO) on July 2, 2012. Equitrans, L.P. (Equitrans) is a Pennsylvania limited partnership and the predecessor for accounting purposes of EQT Midstream Partners. References in this Form 10-K to the “Partnership,” when used for periods prior to the IPO, refer to Equitrans. References in this Form 10-K to the “Partnership,” when used for periods beginning at or following the IPO, refer collectively to the Partnership and its consolidated subsidiaries. Immediately prior to the closing of the IPO, EQT Corporation contributed all of the partnership interests in Equitrans to the Partnership. Therefore, the historical financial statements contained in this Form 10-K reflect the assets, liabilities and operations of Equitrans (excluding the results of operations of Big Sandy Pipeline, a FERC-regulated transmission pipeline sold by Equitrans to an unrelated party in July 2011) for periods ending before July 2, 2012 and EQT Midstream Partners for periods beginning at or following July 2, 2012. Additionally, as discussed below, the Partnership’s consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of Sunrise Pipeline, LLC (Sunrise), which was merged into the Partnership on July 22, 2013, as the transaction was a transfer between entities under common control. References in this Form 10-K to ‘‘EQT’’ refer collectively to EQT Corporation and its consolidated subsidiaries.
Overview
EQT Midstream Partners is a growth-oriented limited partnership formed by EQT Corporation (NYSE: EQT) to own, operate, acquire and develop midstream assets in the Appalachian Basin. The Partnership provides substantially all of its natural gas transmission, storage and gathering services under contracts with fixed reservation and/or usage fees, with a significant portion of its revenues being generated under long-term firm contracts. The Partnership’s operations are primarily focused in southwestern Pennsylvania and northern West Virginia, a strategic location in the rapidly growing natural gas shale play known as the Marcellus Shale. This same region is also the core operating area of EQT, the general partner and a significant equity owner of the Partnership. The Partnership provides midstream services to EQT and multiple third parties across 21 counties in Pennsylvania and West Virginia through its two primary assets: the Transmission and Storage System, which serves as a header system transmission pipeline, and the Gathering System, which delivers natural gas from wells and other receipt points to transmission pipelines. The Partnership believes that its strategically located assets, combined with its working relationship with EQT, position it as a leading Appalachian Basin midstream energy company serving the Marcellus Shale region.
EQT is the Partnership’s largest customer and is one of the largest natural gas producers in the Appalachian Basin. For the year ended December 31, 2013, EQT reported 8.3 Tcfe of proved natural gas and crude oil reserves and total production sales volumes of 378 Bcfe, representing a 43% increase compared to the year ended December 31, 2012. Approximately 73% of EQT’s total production in 2013 was from Marcellus wells, and overall Marcellus volumes increased 82% compared to the year ended December 31, 2012. During the year ended December 31, 2013, approximately 79% of the Partnership’s total natural gas transmission and gathering volumes consists of natural gas produced by EQT and other affiliated volumes. In order to facilitate production growth in its areas of operation, EQT invested approximately $1.4 billion in midstream infrastructure from January 1, 2009 through December 31, 2013 and currently owns a substantial and growing portfolio of midstream assets, many of which have multiple interconnects into the Partnership’s system. The Partnership believes its economic relationship with EQT incentivizes EQT to provide the Partnership with access to additional production growth in and around its existing assets and with acquisitions and organic growth opportunities, although EQT is under no obligation to do so.
Sunrise Merger and Equity Offering in 2013
On July 15, 2013, the Partnership and Equitrans entered into an Agreement and Plan of Merger with EQT and Sunrise, a wholly owned subsidiary of EQT and the owner of the Sunrise Pipeline. Effective July 22, 2013, Sunrise merged with and into Equitrans, with Equitrans continuing as the surviving company. Upon closing, the Partnership paid EQT consideration of $540 million, consisting of a $507.5 million cash payment, 479,184 Partnership common units and 267,942 Partnership general partner units. Prior to the Sunrise Merger, Equitrans entered into a precedent agreement with a third party for firm transportation service on the Sunrise Pipeline over a twenty-year term (the “Precedent Agreement”). Pursuant to the Agreement and Plan of Merger, the Partnership paid
additional consideration of $110 million to EQT in January 2014 following the effectiveness of the transportation agreement contemplated by the Precedent Agreement.
Prior to the Sunrise Merger, the Partnership operated the Sunrise Pipeline as part of its transmission and storage system under a lease agreement with EQT. The lease was a capital lease under GAAP and, as a result, revenues and expenses associated with Sunrise were included in the Partnership’s consolidated financial statements. However, the monthly lease payment to EQT offset the impact of Sunrise operations on the Partnership’s adjusted EBITDA and distributable cash flow. Effective as of the closing of the Sunrise Merger on July 22, 2013, the lease agreement was terminated. As the transaction was a transfer between entities under common control, the Partnership’s historical consolidated financial statements have been retrospectively recast to reflect the results attributable to Sunrise for all periods presented.
On July 22, 2013, the Partnership completed an underwritten public offering of 12,650,000 common units. Net proceeds from the offering were used to finance the cash consideration paid to EQT in connection with the Sunrise Merger. Following the offering and Sunrise Merger, EQT retained a 44.6% equity interest in the Partnership, which includes 3,443,902 common units, 17,339,718 subordinated units and 975,686 general partner units. The Partnership received net proceeds of approximately $529 million from the offering after deducting the underwriters’ discount and offering expenses of approximately $21 million.
Allegheny Valley Connector Facilities
On December 19, 2012, EQT and a direct wholly owned subsidiary entered into a Master Purchase Agreement with PNG Companies LLC (PNG Companies), to transfer 100% ownership of EQT’s LDC, Equitable Gas Company, LLC (Equitable Gas Company) to PNG Companies (the Equitable Gas Transaction). The parties completed the Equitable Gas Transaction on December 17, 2013. As consideration for the Equitable Gas Transaction, EQT received cash proceeds of approximately $740 million, which is subject to certain post-closing adjustments, select midstream assets and commercial arrangements with the PNG Companies and its affiliates. The midstream assets are strategically located to connect the Marcellus supply and demand and are referred to as the Allegheny Valley Connector (AVC) facilities. In connection with EQT’s acquisition of the AVC facilities in the Equitable Gas Transaction, the Partnership entered into a lease agreement with EQT pursuant to which the Partnership markets the capacity on, enters into all agreements for transportation service with customers for, and operates the AVC facilities according to the terms of the Partnership’s FERC tariff.
Transmission and Storage System
The Partnership’s transmission and storage system includes an approximately 700 mile FERC-regulated interstate pipeline that connects to five interstate pipelines and multiple distribution companies. The transmission system is supported by 14 associated natural gas storage reservoirs with approximately 400 MMcf per day of peak withdrawal capability and 32 Bcf of working gas capacity and 24 compressor units. As of December 31, 2013, the transmission assets had total throughput capacity of approximately 2.25 TBtu per day. Through the lease with EQT, the Partnership also operates the AVC facilities, which includes an approximately 200 mile FERC-regulated interstate pipeline that interconnects with the Partnership’s transmission and storage system. The AVC transmission system is supported by 4 associated natural gas storage reservoirs with approximately 260 MMcf per day of peak withdrawal capability and 15 Bcf of working gas capacity and 11 compressor units. Of the total 15 Bcf of working gas capacity, the Partnership leases and operates 13 Bcf of working gas capacity. As of December 31, 2013, the AVC transmission assets had total throughput capacity of approximately 0.45 TBtu per day. Revenues associated with the Partnership’s transmission and storage system represented approximately 94%, 88% and 85% of total revenues for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013, the weighted average remaining contract life based on total projected contracted revenues for firm transmission and storage contracts was approximately 15 years.
The Partnership’s transmission and storage system was initially constructed to receive natural gas from interstate pipelines and local conventional natural gas producers for delivery to LDCs and industrial end-users located in West Virginia and western Pennsylvania, including the city of Pittsburgh. Prompted by the rapid development of the Marcellus Shale in 2007 and the resulting increased supply of natural gas in the region, the Partnership shifted the focus of its transmission and storage system and reengineered its pipeline to act as a header system receiving natural gas produced in the Marcellus Shale. In turn, the system was poised to deliver this
Marcellus gas into interstate pipelines that serve customers throughout the Mid-Atlantic and Northeastern United States, as well as to continue delivering to LDCs and end-users directly connected to the system.
In support of this shift in focus, the Partnership has completed, and continues to work on, numerous projects aimed at increasing system capacity including, but not limited to, the following:
• The Sunrise Pipeline was placed into service in the third quarter of 2012. The Sunrise Pipeline provides access to liquids-rich Marcellus Shale acreage through its 41.5 miles of FERC-regulated transmission pipeline that parallels and interconnects with the segment of the Partnership’s transmission and storage system from Wetzel County, West Virginia to Greene County, Pennsylvania. The Sunrise Pipeline provides approximately 400 BBtu of additional firm capacity to the Partnership’s system and cost approximately $230 million. The Partnership is currently expanding the Jefferson compressor station to provide approximately 550 BBtu per day of additional incremental capacity on the Sunrise Pipeline system. The expansion, which is expected to cost approximately $30 million, is expected to be placed into service in the third quarter of 2014.
• The Blacksville Compressor station project was completed in the third quarter of 2012. It consisted of installing a new booster compressor station in Monongalia County, West Virginia, including two compressor units with an aggregate compression of approximately 9,470 horsepower, at a cost of approximately $30 million. This project provided approximately 200 BBtu per day of incremental firm transmission capacity on the Partnership’s system.
• The Low Pressure East expansion project was placed into service in the fourth quarter of 2013. It involved uprating or replacing 26 miles of existing transmission pipeline in Greene, Washington and Allegheny counties in Pennsylvania at a cost of approximately $30 million. This project tripled the current maximum allowable operating pressure of the pipeline, thereby creating approximately 150 BBtu per day of incremental firm transmission capacity on the Partnership’s system.
• The Partnership’s business also includes the construction and operation of pipelines and compression facilities for third parties under fixed-fee contracts. On December 17, 2013, the Partnership entered into two separate agreements with Antero Resources for firm transportation services on the Partnership’s transmission system. Under each agreement, the Partnership will ultimately provide 100 BBtu per day of firm transmission capacity on the transmission system for a combined total of 200 BBtu per day. As part of the agreements, the Partnership expects to spend approximately $55 million on two separate transmission expansion projects in northern West Virginia. The west-side expansion (the West-Side Expansion project) will add 100 BBtu per day of transmission capacity at an estimated cost of $26 million and is expected to be in full service by year-end 2014. The east-side expansion (the East-Side Expansion project) will add 100 BBtu per day of transmission capacity at an estimated cost of $29 million and is expected to be in full service by mid-year 2015. Combined, the agreements require the Partnership to provide 75 BBtu per day of firm transmission capacity commencing in the second quarter of 2014 and increase to a total of 200 BBtu per day by mid-year 2015. The agreements are primarily fixed-fee, demand based contracts with a 10-year term commencing on the applicable project’s full 100 BBtu per day in-service date. The Partnership expects to spend approximately $30 million on the two projects in 2014, with the remaining $25 million to be spent in 2015.
• In February 2014, the Partnership entered into definitive agreements with a subsidiary of Range Resources Corporation to provide gathering, compression, and transmission services in southwestern Pennsylvania. In 2014, the Partnership expects to invest approximately $30 million in gathering infrastructure and $25 million in a transmission expansion project in conjunction with the agreements. The transmission expansion will add approximately 100 BBtu per day of capacity to the Partnership’s transmission system and is expected to be in service in the fourth quarter of 2014. The agreements include a fee-based 10-year minimum volume commitment for gathering and transmission services.
The Partnership has an acreage dedication from EQT pursuant to which the Partnership has the right to elect to transport on its transmission and storage system all natural gas produced from wells drilled by EQT under an area covering approximately 60,000 acres in Allegheny, Washington and Greene counties in Pennsylvania and
Wetzel, Marion, Taylor, Tyler, Doddridge, Harrison and Lewis counties in West Virginia. EQT has a significant natural gas drilling program in these areas and is expanding its retained midstream infrastructure, which connects to the Partnership’s transmission and storage system, to meet expected production growth.
The Partnership generally provides transmission and storage services in two manners: firm service and interruptible service. Firm transmission contracts obligate the Partnership’s customers to pay a fixed monthly charge to reserve an agreed upon amount of pipeline capacity regardless of the actual pipeline capacity used by a customer during each month. This charge is referred to as a monthly reservation charge. In addition to monthly reservation charges, the Partnership may also collect usage charges when a firm transmission customer uses the capacity it has reserved under these firm transmission contracts. Where applicable, these charges are assessed on the actual volume of natural gas transported on the transmission system. A firm transmission customer is billed a usage charge on volumes in excess of firm usage when the level of natural gas received for delivery from a firm transmission customer exceeds its reserved capacity. A significant portion of the Partnership’s transportation and storage services are provided through firm service agreements.
Transmission and Storage System
Firm storage contracts obligate customers to pay a fixed monthly charge for the firm right to inject, withdraw and store a specified volume of natural gas regardless of the amount of storage capacity actually utilized by the customer. Firm storage customers are also assessed usage charges on the actual quantities of natural gas injected into or withdrawn from storage. A firm service storage customer is billed a usage charge on volumes in excess of firm capacity when the level of gas injected or withdrawn exceeds the customer’s maximum daily withdrawal limit.
Under interruptible service contracts, customers pay fees based on their actual utilization of assets for transmission and storage services. Customers that have executed interruptible contracts are not assured capacity or service on the applicable pipeline and storage facilities. To the extent that physical capacity that is contracted for firm service is not being fully utilized or there is excess capacity that has not been contracted for service, the system can allocate such capacity to interruptible services. The Partnership also provides natural gas “park and loan” services to assist customers in managing short-term gas surpluses or deficits. Under these park and loan service agreements, customers are charged a usage fee based on the quantities of natural gas stored in (park), or borrowed from (loan), the Partnership’s facilities.
The Partnership generally does not take title to the natural gas transported or stored for its customers.
Including AVC and expected future capacity from expansion projects that are not yet fully constructed but for which the Partnership has obtained signed firm transportation and storage agreements, approximately 2.9 TBtu per day of transmission capacity and 32.4 TBtu of storage capacity, respectively, were subscribed under firm transmission and storage contracts as of December 31, 2013. These contracts have a weighted average remaining contract life, based on total projected contracted revenues, of approximately 15 years for transmission contracts and 18 years for storage contracts.
As of December 31, 2013, approximately 15% of the Partnership’s contracted transmission firm capacity was subscribed at the recourse rates (i.e., the maximum rates an interstate pipeline may charge for its services under its tariff) under the Partnership’s tariff. The remaining 85% of contracted transmission firm capacity was subscribed by customers under negotiated rate agreements under the tariff.
Gathering System
The Partnership’s gathering system consists of approximately 1,600 miles of FERC-regulated low-pressure gathering lines that have multiple delivery interconnects with transmission and storage systems. Revenues associated with the Partnership’s gathering system, all of which were generated under interruptible gathering service contracts, represented approximately 6%, 12% and 15% of total revenues for the years ended December 31, 2013, 2012 and 2011, respectively.
The primary term of a typical gathering agreement is one year with month-to-month roll over provisions terminable upon at least 30 days notice. The rates for gathering service are based on the maximum posted tariff rate and assessed on actual receipts into the gathering system. The Partnership also retains a percentage of wellhead natural gas receipts to recover natural gas used to run its compressor stations and other requirements on its gathering system.
Gathering System
The following table provides information regarding the transmission, storage and gathering assets as of December 31, 2013:
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System |
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Approximate |
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Approximate |
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Approximate |
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Transmission and Storage |
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700 |
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80 |
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41,000 |
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AVC |
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200 |
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60 |
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13,000 |
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Gathering |
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1,600 |
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2,300 |
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22,000 |
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The following table provides a revenue breakdown of the Partnership’s contracts by business segment for the year ended December 31, 2013:
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Revenue Composition % |
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Firm Contracts |
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Capacity |
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Interruptible |
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Charges |
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Usage Charges |
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Usage Charges |
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Total |
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Transmission and Storage |
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70% |
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22% |
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2% |
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94% |
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Gathering |
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— |
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— |
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6% |
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6% |
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Strategy
The Partnership’s principal business objective is to increase the quarterly cash distributions that it pays to unitholders over time while ensuring the ongoing stability of its business. The Partnership expects to achieve this objective through the following business strategies:
· Pursuing accretive acquisitions from EQT and third parties. The Partnership intends to seek opportunities to expand its existing natural gas transmission, storage and gathering operations primarily through accretive acquisitions from EQT and third parties. While the Partnership expects that the majority of its most significant opportunities will be sourced from EQT’s existing portfolio of midstream assets or from expansion projects or acquisitions that EQT undertakes in the future as it builds additional midstream assets to support its production growth, the Partnership will evaluate and may pursue acquisition opportunities from third parties as they become available.
· Capitalizing on economically attractive organic growth opportunities. The Partnership expects to grow its systems over time by meeting EQT’s and other third party customers’ midstream service needs that result from their drilling activity in the Partnership’s areas of operations. EQT’s acreage dedication to the Partnership’s assets and EQT’s economic relationship with the Partnership provide a platform for organic growth. In addition, the Partnership intends to leverage EQT’s knowledge of, and expertise in, the Marcellus Shale in order to target and efficiently execute economically attractive organic growth projects for third party customers, although EQT is under no obligation to share such knowledge and expertise with the Partnership. The Partnership will evaluate organic expansion and greenfield construction opportunities in existing and new markets that it believes will increase the volume of transmission, storage and gathering capacity subscribed on its system. The Partnership’s 2014 Jefferson compressor station expansion project is designed to increase the capacity of the transmission and storage system by approximately 550 BBtu per day, which is fully subscribed. This is expected to be placed into service in the third quarter of 2014. Additionally, the Partnership’s 2014 and 2015 expansion projects for third parties will increase the capacity of the transmission and storage system by approximately 300 BBtu per day. These expansion projects are expected to be placed into service by year-end 2014 and mid-year 2015.
· Attracting additional third-party volumes. The Partnership actively markets its midstream services to, and pursues strategic relationships with, third-party producers in order to attract additional volumes and/or expansion opportunities. The Partnership believes that its connectivity to interstate pipelines, which is a key feature of a header system transmission pipeline, as well as its position as an early developer of midstream infrastructure within certain areas of the Marcellus Shale, will allow the Partnership to capture additional third-party volumes in the future. The Partnership anticipates that organic growth projects that it pursues, or any assets it acquires from EQT, will be constructed in a manner that leverages economies of scale to allow for incremental third party volumes in excess of capacity amounts needed by EQT.
· Focusing on stable, fixed-fee business. The Partnership intends to pursue additional opportunities to provide fixed-fee transmission, storage and gathering services to EQT and third parties. The Partnership will focus on obtaining additional long-term firm commitments from customers, which may include reservation-based charges, volume commitments and acreage dedications.
· Increasing access to existing and new delivery markets. The Partnership is actively working to increase delivery interconnects with interstate pipelines, neighboring LDCs, large industrial facilities and electric generation plants in order to increase access to existing and new markets for natural gas consumption. The Partnership’s transmission and storage system has the flexibility to accommodate significant additional throughput to service new end-user markets and it believes that the Partnership’s access to numerous supply sources, including Marcellus Shale production, five interstate pipelines and its on-system storage facilities, which can be used to balance volatile load swings, make the Partnership an attractive option for these end-user delivery markets.
The Partnership’s Relationship with EQT
One of the Partnership’s principal attributes is its relationship with EQT. Headquartered in Pittsburgh, Pennsylvania, in the heart of the Appalachian Basin, EQT is an integrated energy company, with an emphasis on natural gas production, gathering and transmission. EQT conducts its business through two business segments: EQT Production and EQT Midstream. EQT Production is one of the largest natural gas producers in the Appalachian Basin with 8.3 Tcfe of proved natural gas and crude oil reserves across 3.6 million gross acres as of December 31, 2013. EQT Midstream provides transmission, storage and gathering services for EQT’s produced gas and to third parties in the Appalachian Basin.
EQT owns a 2.0% general partner interest in the Partnership, all of the Partnership’s incentive distribution rights and a 42.6% limited partner interest in the Partnership. Because of its ownership of the incentive distribution rights, EQT is positioned to directly benefit from committing additional natural gas volumes to the Partnership’s systems and from facilitating accretive acquisitions and organic growth opportunities. However, EQT is under no obligation to make acquisition opportunities available to the Partnership, is not restricted from competing with the Partnership and may acquire, construct or dispose of midstream assets without any obligation to offer the Partnership the opportunity to purchase or construct these assets.
The Partnership believes that its relationship with EQT is advantageous for the following reasons:
• EQT is a leader among exploration and production companies in the Appalachian Basin. EQT had approximately 3.6 million gross acres as of December 31, 2013, of which approximately 580,000 gross acres were located in the Marcellus Shale. A substantial portion of EQT’s drilling efforts in 2012 and 2013 were focused on drilling horizontal wells in the Marcellus Shale formations of southwestern Pennsylvania and northern West Virginia. For the year ended December 31, 2013, EQT reported total production sales volumes of 378 Bcfe, representing a 43% increase compared to the year ended December 31, 2012. Approximately 73% of EQT’s total production in 2013 was from wells in the Marcellus Shale. EQT Marcellus sales volumes were 82% higher for the year ended December 31, 2013 as compared to the year ended December 31, 2012.
• EQT has a substantial and growing portfolio of midstream assets. The Partnership expects to have the opportunity to purchase additional midstream assets from EQT in the future, although EQT is under no obligation to make the opportunities available to the Partnership. The opportunities are expected to include:
– Retained midstream transmission assets. The AVC facilities include an approximately 200 mile FERC-regulated interstate pipeline that interconnects with the Partnership’s transmission and storage system. The AVC transmission system is supported by 4 associated natural gas storage reservoirs with approximately 260 MMcf per day of peak withdrawal capability and 15 Bcf of working gas capacity and 11 compressor units. As of December 31, 2013, the AVC transmission assets had total throughput capacity of approximately 450 BBtu per day.
– Retained midstream gathering assets. EQT’s retained midstream asset base includes approximately 7,850 miles of gathering pipelines with throughput of approximately 1,220 BBtu of natural gas per day for the year ended December 31, 2013. These retained assets include approximately 120 miles of high-pressure gathering lines serving both liquids-rich and dry areas in the Marcellus Shale located in Greene, Washington, Armstrong, Allegheny, Clearfield, Jefferson and Tioga counties in Pennsylvania and Doddridge, Taylor, Ritchie and Wetzel counties in West Virginia.
– Development of additional midstream assets. EQT continues to expand its exploration and production operations in the Appalachian Basin, primarily in the Marcellus and Utica Shales. As this expansion increases into areas that are currently underserved by midstream infrastructure, the Partnership expects it will develop, either independently or in partnership with EQT, additional midstream assets to ensure takeaway capacity for EQT’s expected production growth. EQT has announced it plans to spend approximately $475 million on midstream infrastructure in 2014 to support its production growth, and expects gathering and transmission volumes to increase as a result of this expansion.
While the Partnership’s relationship with EQT may provide significant benefits, it may also become a source of potential conflicts. For example, EQT is not restricted from competing with the Partnership. In addition, all of the executive officers and a majority of the directors of the Partnership’s general partner also serve as officers and/or directors of EQT, and these officers and directors face conflicts of interest, which include the allocation of their time between the Partnership and EQT. For a description of the Partnership’s relationships with EQT, please read Item 13, “Certain Relationships and Related Transactions, and Director Independence.”
Markets and Customers
For the years ended December 31, 2013, 2012 and 2011, EQT accounted for approximately 77%, 78% and 79%, respectively, of the Partnership’s total revenues. No other customers accounted for more than 10% of revenues during these years. As a result of the Equitable Gas Transaction, revenues related to Equitable Gas Company will be reported as third party revenues in 2014 rather than EQT affiliate revenues. For the years ended December 31, 2013, 2012 and 2011, Equitable Gas Company accounted for approximately 21%, 27% and 35%, respectively, of the Partnership’s total revenues.
Transmission and Storage Customers
The Partnership provides natural gas transmission services for EQT and third parties, predominantly consisting of LDCs, marketers, producers and commercial and industrial users that the Partnership believes to be creditworthy. The Partnership’s transmission system serves not only adjacent markets in Pennsylvania and West Virginia but also provides its customers access to high-demand end-user markets in the Mid-Atlantic and Northeastern United States through 2.4 TBtu per day of delivery interconnect capacity with major interstate pipelines. The Partnership provides storage services to a mix of customers, including marketers and LDCs.
The Partnership’s primary transportation and storage customer is EQT. For the years ended December 31, 2013, 2012 and 2011, EQT and its affiliates accounted for approximately 80%, 81% and 83%, respectively, of transmission revenues and 61%, 68% and 77%, respectively, of storage revenues. Other than EQT, no customer accounted for more than 10% of total transmission and storage revenue for these years.
Gathering Customers
The Partnership’s gathering system currently has approximately 2,300 receipt points with a number of natural gas producers. EQT represented approximately 53% of the 58 BBtu per day of natural gas supplied to the gathering system in 2013, approximately 63% of the 78 BBtu per day of natural gas supplied to the gathering system in 2012 and approximately 63% of the 78 BBtu per day of natural gas supplied to the gathering system in 2011. The Partnership has gathering agreements conforming to its tariff with marketers and distribution companies that purchase natural gas from receipt points on the system for delivery to the interstate pipeline market.
Dominion Field Services generally provides any necessary processing for the gas gathered by the Partnership’s gathering system. In connection with the Partnership’s sale of certain processing plants to Dominion Field Services in 2000, it entered into an agreement with a primary term through December 31, 2014 pursuant to which Dominion Field Services is obligated to process any wet gas the Partnership delivers to certain processing facilities up to the individual operating capacity of each plant. During the years ended December 31, 2013, 2012 and 2011, 70%, 77% and 76%, respectively, of the natural gas supplied to the Partnership’s gathering system was processed by Dominion Field Services. The Partnership’s gathering customers are responsible for the costs associated with treating and processing natural gas in order to meet pipeline specifications, and are required to have processing agreements in place with Dominion Field Services or another processor as a prerequisite to receiving transportation service on its gathering system.
Competition
Competition for natural gas transmission and storage volumes is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, services levels, location, reputation and fuel efficiencies. The Partnership’s principal competitors in its natural gas transmission and storage market include companies that own major natural gas pipelines. In addition, the Partnership competes with companies that are building high pressure gathering facilities that are not subject to FERC jurisdiction to move volumes to interstate
pipelines. EQT also owns, and in the future may construct, natural gas transmission pipelines and high-pressure gathering facilities. Major pipeline natural gas transmission companies that compete with the Partnership also have existing storage facilities connected to their transmission systems that compete with certain of the Partnership’s storage facilities. Pending and future third-party construction projects, if and when brought on-line, may also compete with the Partnership’s natural gas transmission and storage services and many of its competitors have capital and other resources far greater than the Partnership. These third-party projects may include FERC-certificated expansions and greenfield construction projects.
Key competitors for new low-pressure gathering systems include independent gas gatherers and integrated energy companies. Many of the Partnership’s competitors have capital resources and control supplies of natural gas greater than it does. The Partnership’s major competitors for natural gas supplies and markets in its operating regions include Dominion Transmission, local distribution companies and producers constructing their own gathering systems.
Regulatory Environment
FERC Regulation
The Partnership’s interstate natural gas transportation and storage operations are regulated by FERC under the NGA, the NGPA and the Energy Policy Act of 2005. The Partnership’s system operates under a tariff approved by FERC that establishes rates, cost recovery mechanisms and the terms and conditions of service to its customers. Generally, FERC’s authority extends to:
• rates and charges for natural gas transmission, storage and gathering services;
• certification and construction of new interstate transportation and storage facilities;
• extension or abandonment of interstate transportation and storage services and facilities;
• maintenance of accounts and records;
• relationships between pipelines and certain affiliates;
• terms and conditions of services and service contracts with customers;
• depreciation and amortization policies;
• acquisition and disposition of interstate transportation and storage facilities; and
• initiation and discontinuation of interstate transportation and storage services.
The Partnership holds certificates of public convenience and necessity for its transmission and storage system issued by FERC pursuant to Section 7 of the NGA covering rates, facilities, activities and services. These certificates require the Partnership to provide open-access services on its interstate pipeline and storage facilities on a non-discriminatory basis to all customers that qualify under the FERC gas tariff. In addition, under Section 8 of the NGA, FERC has the power to prescribe the accounting treatment of certain items for regulatory purposes. Thus, the books and records of the Partnership’s interstate pipeline and storage facilities may be periodically audited by FERC.
FERC regulates the rates and charges for transportation and storage in interstate commerce. Under the NGA, rates charged by interstate pipelines must be just and reasonable. FERC’s cost-of-service regulations generally limit the recourse rates for transportation and storage services to the cost of providing service plus a reasonable rate of return. In each rate case, FERC must approve service costs, the allocation of costs, the allowed rate of return on capital investment, rate design and other rate factors. A negative determination on any of these rate factors could adversely affect the Partnership’s business, financial condition, results of operations, liquidity and ability to make distributions.
The recourse rate that the Partnership may charge for its services is established through FERC’s ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of providing that service including recovery of and a return on the pipeline’s actual prudent historical cost of investment. Key determinants in the ratemaking process include the depreciated capital costs of the facilities, the costs of providing service, the allowed rate of return and volume throughput and contractual capacity commitment assumptions. The maximum applicable recourse rates and terms and conditions for service are set forth in the pipeline’s FERC approved tariff. Rate design and the allocation of costs also can impact a pipeline’s profitability. While the ratemaking process establishes the maximum rate that can be charged, interstate pipelines such as the Partnership’s transmission and storage system are permitted to discount their firm and interruptible rates without further FERC
authorization down to the variable cost of performing service, provided they do not “unduly discriminate.” In addition, pipelines are allowed to negotiate different rates with their customers, as described below.
Pursuant to the NGA, changes to rates or terms and conditions of service can be proposed by a pipeline company under Section 4, or the existing interstate transportation and storage rates or terms and conditions of service may be challenged by a complaint filed by interested persons including customers, state agencies or the FERC under Section 5. Rate increases proposed by a pipeline may be allowed to become effective subject to refund, while rates or terms and conditions of service which are the subject of a complaint under Section 5 are subject to prospective change by FERC. Rate increases proposed by a regulated interstate pipeline may be challenged and such increases may ultimately be rejected by FERC. Any successful challenge against rates charged for the Partnership’s transportation and storage services could have a material adverse effect on its business, financial condition, results of operations, liquidity and ability to make distributions.
The Partnership’s interstate pipeline may also use negotiated rates which could involve rates above or below the recourse rate or rates that are subject to a different rate structure, provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. A prerequisite for allowing the negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline’s recourse rates. As of December 31, 2013, approximately 85% of the system’s contracted firm transportation capacity was committed under such negotiated rate contracts. Each negotiated rate transaction is designed to fix the negotiated rate for the term of the firm transportation agreement and the fixed rate is generally not subject to adjustment for increased or decreased costs occurring during the contract term.
FERC regulations also extend to the terms and conditions set forth in agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the form of service agreements set forth in the pipeline’s FERC-approved tariff. In the event that the FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement, require the Partnership to seek modification of the agreement or require the Partnership to modify its tariff so that the non-conforming provisions are generally available to all customers.
FERC Regulation of Gathering Rates and Terms of Service
While the FERC does not generally regulate the rates and terms of service over facilities determined to be performing a natural gas gathering function, it has traditionally regulated rates charged by interstate pipelines for gathering services performed on the pipeline’s own gathering facilities when those gathering services are performed in connection with jurisdictional interstate transportation. The Partnership maintains rates and terms of service in its tariff for unbundled gathering services performed on its gathering facilities in connection with the transportation service. Just as with rates and terms of service for transmission and storage services, the Partnership’s rates and terms of services for its gathering system may be challenged by complaint and are subject to prospective change by the FERC. Rate increases and changes to terms and conditions of service the Partnership proposes for its gathering service may be protested and such increases or changes may ultimately be rejected by the FERC.
Pipeline Safety and Maintenance
The Partnership’s interstate natural gas pipeline system is subject to regulation by PHMSA. PHMSA has established safety requirements pertaining to the design, installation, testing, construction, operation and maintenance of gas pipeline facilities, including requirements that pipeline operators develop a written qualification program for individuals performing covered tasks on pipeline facilities and implement pipeline integrity management programs. These integrity management plans require more frequent inspections and other preventive measures to ensure safe operation of oil and natural gas transportation pipelines in “high consequence areas,” such as high population areas or facilities that are hard to evacuate and areas of daily concentrations of people.
Notwithstanding the investigatory and preventive maintenance costs incurred in the Partnership’s performance of customary pipeline management activities, significant additional expenses may be incurred if anomalous pipeline conditions are discovered or more stringent pipeline safety requirements are implemented. For example, on August 25, 2011, PHMSA published an advance notice of proposed rulemaking in which the agency solicited public comment on a number of changes to its natural gas transmission pipeline regulations contained in federal regulations including: (i) modifying the definition of high consequence areas; (ii) strengthening integrity
management requirements as they apply to existing regulated operators; (iii) strengthening or expanding various non-integrity pipeline management standards relating to such matters as valve spacing, automatic or remotely-controlled valves, corrosion protection and gathering lines; and (iv) adding new regulations to govern the safety of underground natural gas storage facilities including underground storage caverns and injection withdrawal well piping that are not currently regulated under the federal regulations. PHMSA has specifically indicated an intent in this advance notice of proposed rulemaking to address the need for standards governing the safety of underground natural gas storage facilities. Following the publication of the advance notice, Congress enacted legislation that will likely subsume this rulemaking process.
On January 3, 2012, President Obama signed into law the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. The Act increases the maximum civil penalties for administrative enforcement actions, requires the DOT to study and report on the sufficiency of existing gathering line regulations to ensure safety and the use of leak detection systems by hazardous liquid pipelines, requires pipeline operators to verify their records on maximum allowable operating pressure and imposes new emergency response and incident notification requirements. On September 25, 2013, PHMSA released a final rule increasing the civil penalty maximums for pipeline safety violations. The rule increased the maximum penalties from $100,000 to $200,000 per day for each violation and from $1,000,000 to $2,000,000 for a related series of violations. The rule applies safety regulations to certain rural low-stress hazardous liquid pipelines not previously covered by some of its safety regulations. PHMSA has also published advance notice of proposed rulemakings to solicit comments on the need for other changes to its natural gas and hazardous liquid pipeline safety regulations, including gathering lines. PHMSA also published an advisory bulletin providing guidance to natural gas transmission operators of the need to verify records related to the maximum allowable operating pressure for each section of a pipeline system. As required by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, the Partnership verified its records for all applicable pipeline segments and submitted a report to DOT identifying each pipeline segment for which records were insufficient.
States are largely preempted by federal law from regulating interstate pipeline safety but may assume responsibility for enforcement of federal interstate pipeline safety regulations for certain intrastate facilities. For example, a Pennsylvania statute authorized the PA PUC to enforce federal regulations applicable to intrastate gathering lines as well as non-FERC certificated transmission lines. In practice, states vary considerably in their authority and capacity to address pipeline safety. The Partnership does not anticipate any significant problems in complying with any state laws and regulations which are determined to be applicable to its operations. The Partnership’s natural gas pipelines have inspection and compliance programs designed to maintain compliance with federal and state pipeline safety and pollution control requirements.
The Partnership believes that its operations are in substantial compliance with all existing federal, state and local pipeline safety laws and regulations and that its compliance with such laws and regulations will not have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to make distributions, but the Partnership can provide no assurance that the adoption of new laws and regulations such as those proposed by PHMSA will not result in significant added costs that could have such a material adverse effect in the future.
Pipeline Safety Cost Rate
The Partnership previously maintained a PSCT, which was a cost recovery mechanism for qualifying costs incurred by the Partnership under the PSIA. The qualifying costs recoverable through the PSCT included a rate of return, taxes and depreciation associated with capital investments and actual operating and maintenance expenses incurred under the PSIA. The PSCT surcharge was a usage charge expressed in dollars per Dth and was assessed to firm and interruptible transmission service customers. The Partnership was required to track all expenses and capital investments associated with the PSIA made on and after September 1, 2005. The Partnership made annual filings with the FERC to adjust the PSCT surcharge to reconcile actual historic qualifying costs incurred against PSCT revenues collected.
On March 1, 2012, Equitrans made its annual filing with the FERC to recover costs it incurred to comply with the PSIA. The filing provided for the recovery of $10.4 million in qualifying pipeline safety costs. One customer and the Independent Oil and Gas Association filed protests which asserted, among other things, that Equitrans had not included all the appropriate volumes in calculating the level of its surcharge. Equitrans responded to the protests and in an order issued March 30, 2012 the FERC accepted the annual filing and suspended it,
allowing the surcharge to become effective on April 1, 2012. Equitrans submitted additional information to the FERC on April 19, 2012 with the expectation that the FERC would subsequently issue an order based on the material Equitrans submitted.
On January 14, 2013, following numerous discussions with its customers, Equitrans filed a Stipulation and Agreement of Settlement (the Settlement) with the FERC. The Settlement, which was approved by the FERC on March 22, 2013, resolved all issues arising out of the Partnership’s 2012 PSCT annual filing. The Settlement eliminated the tracking of PSIA costs and replaced the PSCT surcharge with a Pipeline Safety Cost (PSC) rate effective April 1, 2013. The new PSC rate has both a reservation and a usage component. The reservation component of the PSC rate applicable to firm transportation service is $0.8108 per Dth of the contract Maximum Daily Quantity (MDQ) applicable to service provided on the mainline system and the usage component is $0.1372 per Dth delivered to the customer. The PSC rate applicable to volumes in excess of firm service, no-notice firm transportation service nominated on a point to point basis and interruptible service is $0.1372 per Dth delivered to the customer. Additionally, under the Settlement, Equitrans reduced its transmission retainage factor approved in Equitrans’ most recent rate case from 3.72% to 2.72% effective February 1, 2013. Equitrans no longer tracks its continued recovery of base storage gas. To the extent that Equitrans over-recovers its actual fuel and other gas usage, the excess gas could be used to replenish storage base gas. The PSC rate and transmission retainage factor will be in effect for a minimum of three years.
Environmental, Health and Safety Regulation
The Partnership’s natural gas transportation, storage and gathering activities are subject to various types of federal, state and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges, solid waste management and employee health and safety. Such laws and regulations generally require the Partnership to obtain and comply with a wide variety of environmental registrations, licenses, permits and other approvals. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.
The Partnership believes that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to make distributions. Nevertheless, environmental regulatory programs continue to evolve and future regulations may place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts the Partnership currently anticipates.
The Partnership has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material to the Partnership’s business, financial condition, results of operations, liquidity or ability to make distributions.
Climate Change
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. Effective January 1, 2011, the EPA began regulating greenhouse gas emissions by subjecting new facilities and major modifications to existing facilities that emit large amounts of greenhouse gases to the permitting requirements of the federal Clean Air Act. In addition, the U.S. Congress has been considering bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. Legislation or regulation that restricts carbon emissions could increase the Partnership’s cost of environmental compliance by requiring the Partnership to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Climate change and greenhouse gas legislation or regulation could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities or impose additional monitoring and reporting requirements. Conversely, legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Partnership by increasing demand for natural gas because the combustion of natural gas results in substantially fewer carbon emissions per Btu of heat
generated than other fossil fuels such as coal. The effect on the Partnership of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
Seasonality
Weather impacts natural gas demand for power generation and heating purposes. Peak demand for natural gas typically occurs during the winter months as a result of the heating load.
Title to Properties and Rights-of-Way
The Partnership’s real property falls into two categories: (i) parcels that it owns in fee and (ii) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for the Partnership’s operations. Portions of the land on which the Partnership’s pipelines and facilities are located are owned by the Partnership in fee title, and it believes that it has satisfactory title to these lands. The remainder of the land on which the Partnership’s pipelines and facilities are located are held by the Partnership pursuant to surface leases between the Partnership, as lessee, and the fee owner of the lands, as lessors. The Partnership has leased or owned much of these lands for many years without any material challenge known to the Partnership relating to the title to the land upon which the assets are located, and it is believed that the Partnership has satisfactory leasehold estates or fee ownership to such lands. The Partnership believes that it has satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses, and the Partnership has no knowledge of any material challenge to its title to such assets or their underlying fee title.
However, there are certain lands within the Partnership’s storage pools as to which it does not currently have real property rights. The Partnership has identified the lands as to which it believes it must obtain such rights and is in the midst of a program to acquire such rights. Since the beginning of this program in 2009 through December 31, 2013, the Partnership has successfully acquired such rights for approximately 18,576 acres out of a total 46,452 acres, and the Partnership expects to acquire the remainder within the next three years. In accordance with the Partnership’s FERC license, the geological formations within which its permitted storage facilities are located cannot be used by third parties in any way that would detrimentally affect its storage operations and the Partnership has the power of eminent domain with respect to the acquisition of necessary real property rights to use such storage facilities. The Partnership believes the cost to acquire such rights will be approximately $6 million over the next three years.
Some of the leases, easements, rights-of-way, permits and licenses which were transferred to the Partnership at the closing of the IPO in July 2012 required the consent of the grantor of such rights, which in certain instances is a governmental entity. The Partnership obtained, prior to the closing of the IPO, sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable it to operate its business in all material respects.
EQT and its affiliates continue to hold record title to portions of certain assets until the Partnership makes the appropriate filings in the jurisdictions in which such assets are located and obtains any consents and approvals that were not obtained prior to transfer. Such consents and approvals would include those required by federal and state agencies or political subdivisions. In some cases, EQT may, where required consents or approvals have not been obtained, temporarily hold record title to property as nominee for the Partnership’s benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, cause its affiliates to retain title as nominee for the Partnership’s benefit until a future date. The Partnership anticipates that there will be no material change in the tax treatment of its common units resulting from EQT holding the title to any part of such assets subject to future conveyance or as the Partnership’s nominee.
Insurance
The Partnership generally shares insurance coverage with EQT, for which it reimburses EQT pursuant to the terms of the omnibus agreement. The Partnership’s insurance program includes general liability insurance, auto liability insurance, workers’ compensation insurance and property insurance. In addition, the Partnership has procured a separate general liability policy. All insurance coverage is in amounts which management believes are reasonable and appropriate.
Facilities
EQT leases its corporate offices in Pittsburgh, Pennsylvania. Pursuant to the omnibus agreement, the Partnership pays a proportionate share of EQT’s costs to lease the building.
Employees
The Partnership does not have any employees. The Partnership is managed by the directors and officers of its general partner. All of the Partnership’s executive management personnel are employees of EQT or an affiliate of EQT and devote the portion of their time to the Partnership’s business and affairs that is required to manage and conduct its operations. The daily business operations of the Partnership are conducted by EQT Gathering, LLC (EQT Gathering), one of EQT’s operating subsidiaries. Under the terms of the omnibus agreement with EQT, the Partnership reimburses EQT for the provision of general and administrative services for its benefit, for direct expenses incurred by EQT on the Partnership’s behalf, for expenses allocated to the Partnership as a result of it being a public entity and for operation and management services provided by EQT Gathering.
Availability of Reports
The Partnership makes certain filings with the SEC, including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through its website, http://www.eqtmidstreampartners.com, as soon as reasonably practicable after the date they are filed with, or furnished to, the SEC. The filings are also available at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. These filings are also available on the internet at http://www.sec.gov.
Composition of Segment Operating Revenues
Presented below are operating revenues by segment as a percentage of total operating revenues of the Partnership.
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For the year ended December 31, |
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2013 |
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2012 |
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2011 |
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Transmission and storage operating revenues |
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94% |
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88% |
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85% |
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Gathering operating revenues |
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6% |
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12% |
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15% |
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Financial Information about Segments
See Note 3 to the Consolidated Financial Statements for financial information by business segment including, but not limited to, revenues from external customers, operating income and total assets, which information is incorporated herein by reference.
Jurisdiction and Year of Formation
EQT Midstream Partners, LP is a Delaware limited partnership formed in January 2012.
Financial Information about Geographic Areas
All of the Partnership’s assets and operations are located in the continental United States.
Risks Relating to Our Business
In addition to the other information contained in this Annual Report on Form 10-K, the following risk factors should be considered in evaluating our business and future prospects. Please note that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations. If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations, liquidity or ability to make distributions could suffer and the trading price of our common units could decline.
We are dependent on EQT for a substantial majority of our revenues and future growth. Therefore, we are indirectly subject to the business risks of EQT. We have no control over EQT’s business decisions and operations, and EQT is under no obligation to adopt a business strategy that favors us.
Historically, we have provided a substantial percentage of our natural gas transmission, storage and gathering services to EQT. During the year ended December 31, 2013, approximately 77% of our revenues were from EQT. We expect to derive a substantial majority of our revenues from EQT for the foreseeable future. Therefore, any event, whether in our area of operations or otherwise, that adversely affects EQT’s production, financial condition, leverage, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the business risks of EQT, including the following:
• natural gas price volatility may have an adverse effect on its drilling operations, revenue, profitability, future rate of growth and liquidity;
• infrastructure capacity constraints and interruptions;
• risks associated with the operation of its wells, pipelines and facilities, including potential environmental liabilities;
• the availability of capital on a satisfactory economic basis to fund its operations;
• its ability to identify production opportunities based on market conditions;
• uncertainties inherent in projecting future rates of production;
• its ability to develop additional reserves that are economically recoverable, to optimize existing well production and sustain production;
• adverse effects of governmental and environmental regulation and negative public perception regarding its operations; and
• the loss of key personnel.
Unless we are successful in attracting significant unaffiliated third-party customers, our ability to maintain or increase the capacity subscribed and volumes transported under service arrangements on our transmission and storage system as well as the volumes gathered on our gathering system will be dependent on receiving consistent or increasing commitments from EQT. While EQT has dedicated acreage to, and entered into long-term firm transportation contracts on, our systems, it may determine in the future that drilling in areas outside of our current areas of operations is strategically more attractive to it and it is under no contractual obligation to maintain its production dedicated to us. A reduction in the capacity subscribed or volumes transported, stored or gathered on our systems by EQT could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to EQT and its affiliates, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.
In order to pay the minimum quarterly distribution of $0.35 per unit, or $1.40 per unit on an annualized basis, we will require available cash of approximately $17.1 million per quarter, or $68.3 million per year, based on the number of common, subordinated and general partner units outstanding at December 31, 2013. We may not have sufficient available cash each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
• the rates we charge for our transmission, storage and gathering services;
• the level of firm transmission and storage capacity sold and volumes of natural gas we transport, store and gather for our customers;
• regional, domestic and foreign supply and perceptions of supply of natural gas; the level of demand and perceptions of demand in our end-use markets; and actual and anticipated future prices of natural gas and other commodities (and the volatility thereof), which may impact our ability to renew and replace firm transmission and storage agreements;
• the effect of seasonal variations in temperature on the amount of natural gas that we transport, store and gather;
• the level of competition from other midstream energy companies in our geographic markets;
• the creditworthiness of our customers;
• the level of our operating, maintenance and general and administrative costs;
• regulatory action affecting the supply of, or demand for, natural gas, the rates we can charge on our assets, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and
• prevailing economic conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:
• the level and timing of capital expenditures we make;
• the level of our operating and general and administrative expenses, including reimbursements to our general partner and its affiliates, including EQT, for services provided to us;
• the cost of acquisitions, if any;
• our debt service requirements and other liabilities;
• fluctuations in our working capital needs;
• our ability to borrow funds and access capital markets;
• restrictions on distributions contained in our debt agreements;
• the amount of cash reserves established by our general partner; and
• other business risks affecting our cash levels.
Our natural gas transportation, storage and gathering services are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make distributions.
Our interstate natural gas transportation and storage operations are regulated by the FERC under the NGA, the NGPA, and the Energy Policy Act of 2005. Our gathering operations are also rate-regulated by the FERC in connection with our interstate transportation operations. Our system operates under a tariff approved by the FERC that establishes rates, cost recovery mechanisms and terms and conditions of service to our customers. Generally, the FERC’s authority extends to:
• rates and charges for our natural gas transmission, storage and gathering services;
• certification and construction of new interstate transmission and storage facilities;
• abandonment of interstate transmission and storage services and facilities;
• maintenance of accounts and records;
• relationships between pipelines and certain affiliates;
• terms and conditions of services and service contracts with customers;
• depreciation and amortization policies;
• acquisition and disposition of interstate transmission and storage facilities; and
• initiation and discontinuation of interstate transmission and storage services.
Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust and unreasonable or unduly discriminatory. The recourse rate that may be charged by our interstate pipeline for its transmission and storage services is established through the FERC’s ratemaking process. The maximum applicable recourse rate and terms and conditions for service are set forth in our FERC-approved tariff.
Pursuant to the NGA, existing interstate transportation and storage rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases and changes to terms and conditions of service proposed by a regulated interstate pipeline may be protested and such increases or changes can be delayed and may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i) “recourse rates” (i.e., the maximum rates an interstate pipeline may charge for its services under its tariff) and (ii) “negotiated rates” which generally involve rates above the “recourse rates,” provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. As of December 31, 2013, approximately 85% of our system’s contracted firm transportation capacity was committed under such “negotiated rate” contracts, rather than recourse rate or discount rate contracts. There can be no guarantee that we will be allowed to continue to operate under such rate structures for the remainder of those assets’ operating lives. Any successful challenge against rates charged for our transportation and storage services could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make distributions.
While the FERC does not generally regulate the rates and terms of service over facilities determined to be performing a natural gas gathering function, the FERC has traditionally regulated rates charged by interstate pipelines for gathering services performed on the pipeline’s own gathering facilities when those gathering services are performed in connection with jurisdictional interstate transmission facilities. We maintain rates and terms of service in our tariff for unbundled gathering services performed on our gathering facilities, which are connected to our transmission and storage system. Just as with rates and terms of service for transportation and storage services, our rates and terms of services for our gathering may be challenged by complaint and are subject to prospective change by the FERC. Rate increases and changes to terms and conditions of service which we propose for our gathering service may be protested and such increases or changes can be delayed and may ultimately be rejected by the FERC.
The FERC’s jurisdiction extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to, acquisitions, facility maintenance, expansions, and abandonment of facilities and services. While the FERC exercises jurisdiction over the rate and terms of service for our gathering operations, our gathering facilities are not subject to the FERC’s certification and construction authority. Prior to commencing construction of new or existing interstate transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or file to amend its existing certificate, from the FERC. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any refusal by an agency to issue authorizations or permits for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate. Such refusal or modification could materially and negatively impact the additional revenues expected from these projects.
FERC regulations also extend to the terms and conditions set forth in agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the form of service agreements set forth in the pipeline’s FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that the FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement or require us to seek modification, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers.
Under current policy, the FERC permits interstate pipelines to include an income tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines owned by partnerships or limited liability companies taxed as partnerships for federal income tax purposes, the tax allowance will reflect the actual or potential income tax liability on the FERC-jurisdictional income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. This policy was upheld on May 29, 2007 by the Court of Appeals for the District of Columbia Circuit. The FERC will determine, on a case-by-case basis, whether the owners of an interstate pipeline have such actual or potential income tax liability. In a future rate case, we may be required to demonstrate the extent to which inclusion of an income tax allowance in the applicable cost-of-service is permitted under the current income tax allowance policy. In addition, the FERC’s income tax allowance policy is frequently the subject of challenge, and we cannot predict
whether the FERC or a reviewing court will alter the existing policy. If the FERC’s policy were to change and if the FERC were to disallow a substantial portion of our pipeline’s income tax allowance, our regulated rates, and therefore our revenues and ability to make distributions, could be materially adversely affected.
The FERC may not continue to pursue its approach of pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities.
Failure to comply with applicable provisions of the NGA, the NGPA, the Pipeline Safety Act of 1968 and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to $1,000,000 per day, per violation.
In addition, future federal, state, or local legislation or regulations under which we will operate our natural gas transportation, storage and gathering businesses may have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make distributions to our unitholders.
Any significant decrease in production of natural gas in our areas of operation could adversely affect our business and operating results and reduce our distributable cash flow.
Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. Low prices for natural gas or regulatory limitations could adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets. Production from existing wells and natural gas supply basins with access to our systems will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers or lower natural gas prices could cause producers to determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. A reduction in the natural gas volumes supplied by EQT or other third party producers could result in reduced throughput on our systems and adversely impact our ability to grow our operations and increase cash distributions to our unitholders. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported, stored and gathered on our systems and cash flows associated therewith, our customers must continually obtain adequate supplies of natural gas.
The primary factors affecting our ability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity near our systems and (ii) our ability to compete for volumes from successful new wells. While EQT has dedicated production from certain of its leased properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering system or the rate at which production from a well declines. In addition, we have no control over EQT or other producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for hydrocarbons, levels of reserves, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs, and other production and development costs.
Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported liquefied natural gas (LNG); the ability to export LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials and premiums; the price and availability of alternative fuels; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, LNG and other commodities. Declines in natural gas prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our systems. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Moreover, EQT may not develop the acreage it has dedicated
to us. If reductions in drilling activity result in our inability to maintain levels of contracted capacity and throughput, it could reduce our revenue and impair our ability to make quarterly cash distributions to our unitholders.
In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems in unconventional resource plays such as the Marcellus Shale, as the basins in those plays generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Furthermore, our gathering assets were initially constructed as a low-pressure system designed for shallow, vertical wells and Marcellus Shale production is increasingly from horizontal wells at higher pressure than our existing gathering assets were designed to handle. If natural gas prices remain low, production in the area around our low-pressure gathering system may continue to decline. Accordingly, volumes on our gathering system would need to be replaced at a faster rate to maintain or grow the current volumes than may be the case in other regions of production. Should we determine that the economics of our gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time.
If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins, or if natural gas supplies are diverted to serve other markets, the overall volume of natural gas transported and stored on our systems would decline, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and on our ability to make quarterly cash distributions to our unitholders.
We may not be able to increase our third-party throughput and resulting revenue due to competition and other factors, which could limit our ability to grow and extend our dependence on EQT.
Part of our growth strategy includes diversifying our customer base by identifying opportunities to offer services to third parties other than EQT. For the years ended December 31, 2013, 2012 and 2011, EQT accounted for approximately 80%, 81% and 83%, respectively, of our transmission revenues, 61%, 68% and 77%, respectively, of our storage revenues, 54%, 64% and 64%, respectively, of our gathering revenues and 77%, 78% and 79%, respectively, of our total revenues. Our ability to increase our third-party throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when third-party shippers require it. To the extent that we lack available capacity on our systems for third-party volumes, we may not be able to compete effectively with third-party systems for additional natural gas production in our areas of operation.
We have historically provided transmission, storage and gathering services to third parties on only a limited basis, and we may not be able to attract material third-party service opportunities. Our efforts to attract new unaffiliated customers may be adversely affected by our relationship with EQT and our desire to provide services pursuant to fee-based contracts. Our potential customers may prefer to obtain services under other forms of contractual arrangements under which we would be required to assume direct commodity exposure, and potential customers may desire to contract for gathering services that are not subject to FERC regulation. In addition, we will need to continue to improve our reputation among our potential customer base for providing high quality service in order to continue to successfully attract unaffiliated third parties.
We are exposed to the credit risk of our customers in the ordinary course of our business.
We extend credit to our customers as a normal part of our business. As a result, we are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers. While we have established credit policies, including assessing the creditworthiness of our customers as permitted by our FERC-approved natural gas tariff, and requiring appropriate terms or credit support from them based on the results of such assessments, we may not have adequately assessed the creditworthiness of our existing or future customers. Furthermore, unanticipated future events could result in a deterioration of the creditworthiness of our contracted customers, including EQT. Any resulting nonpayment and/or nonperformance by our customers could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Increased competition from other companies that provide transmission, storage or gathering services, or from alternative fuel sources, could have a negative impact on the demand for our services, which could adversely affect our financial results.
Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our systems compete primarily with other interstate and intrastate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors have greater financial resources and may now, or in the future, have access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own transmission, storage or gathering services instead of using ours. Moreover, EQT and its affiliates are not limited in their ability to compete with us.
The policies of the FERC promoting competition in natural gas markets are having the effect of increasing the natural gas transportation and storage options for our traditional customer base. As a result, we could experience some “turnback” of firm capacity as existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported or stored by our systems or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates.
Further, natural gas as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas storage and transportation services.
All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas, our revenues and cash available to make distributions to our unitholders could be adversely affected.
We depend upon third-party pipelines and other facilities that provide receipt and delivery options to and from our transmission and storage system. For example, our transmission and storage system interconnects with the following interstate pipelines: Texas Eastern, Dominion Transmission, Columbia Gas Transmission, Tennessee Gas Pipeline Company and National Fuel Gas Supply Corporation, as well as multiple distribution companies. Similarly, our gathering system has multiple delivery interconnects to the Dominion Transmission system. Additionally, substantially all of the natural gas that is gathered by our gathering system that requires processing and treating is handled by Dominion Transmission. In the event that our access to such facility was impaired or if we were unable to maintain processing and treating contracts on acceptable terms, the amount of natural gas that our gathering system can gather and transport onto our transmission and storage system would be adversely affected, which could reduce revenues from our gathering activities. Because we do not own these third party pipelines or facilities, their continuing operation is not within our control. If these or any other pipeline connections or facilities were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect or facility could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Certain of the services we provide on our transmission and storage system are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.
It is possible that costs to perform services under “negotiated rate” contracts will exceed the negotiated rates. If this occurs, it could decrease the cash flow realized by our systems and, therefore, the cash we have available for distribution to our unitholders. Under FERC policy, a regulated service provider and a customer may
mutually agree to sign a contract for service at a “negotiated rate,” which is generally above the FERC-regulated “recourse rate” for that service, and that contract must be filed with and accepted by the FERC. As of December 31, 2013, approximately 85% of our contracted transmission firm capacity was subscribed under such “negotiated rate” contracts. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be caused by inflation or other factors relating to the specific facilities being used to perform the services.
We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.
Our primary exposure to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal. As of December 31, 2013, the weighted average remaining contract life based on total projected contracted revenues for our firm transmission and storage contracts was approximately 15 years. The extension or replacement of existing contracts, including our contracts with EQT, depends on a number of factors beyond our control, including:
• the level of existing and new competition to provide services to our markets;
• the macroeconomic factors affecting natural gas economics for our current and potential customers;
• the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
• the extent to which the customers in our markets are willing to contract on a long-term basis; and
• the effects of federal, state or local regulations on the contracting practices of our customers.
Any failure to extend or replace a significant portion of our existing contracts, or extending or replacing them at unfavorable or lower rates, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
If the tariff governing the services we provide is successfully challenged, we could be required to reduce our tariff rates, which would have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
The Settlement associated with the PSCT provides that the Partnership will not file a general rate case on or before October 1, 2015 and that the parties to the Settlement will not file a challenge to such rates prior to December 31, 2015. However, the FERC, or other interested stakeholders, such as state regulatory agencies, may still challenge the recourse rates or the terms and conditions of service included in our tariff. We do not have an agreement in place that would prohibit EQT or its affiliates from challenging our tariff. If any challenge were successful, among other things, the rates that we charge on our systems could be reduced. Successful challenges could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
If we are unable to make acquisitions on economically acceptable terms from EQT or third parties, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants, including EQT. We have no contractual arrangement with EQT that would require it to provide us with an opportunity to offer to purchase midstream assets that it may sell. Accordingly, while we believe EQT will be incentivized pursuant to its economic relationship with us to offer us opportunities to purchase midstream assets, there can be no assurance that any such offer will be made. Furthermore, many factors could impair our access to future midstream assets and the willingness of EQT to offer us acquisition opportunities, including a change in control of EQT or a transfer of the incentive distribution rights by our general partner to a third party. A material decrease in divestitures of midstream energy assets from EQT or otherwise would limit our opportunities for future acquisitions and could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
If we are unable to make accretive acquisitions from EQT or third parties, whether because, among other reasons, (i) EQT elects not to sell or contribute additional assets to us or to offer acquisition opportunities to us, (ii) we are unable to identify attractive third-party acquisition opportunities, (iii) we are unable to negotiate
acceptable purchase contracts with EQT or third parties, (iv) we are unable to obtain financing for these acquisitions on economically acceptable terms, (v) we are outbid by competitors or (vi) we are unable to obtain necessary governmental or third-party consents, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.
Any acquisition involves potential risks, including, among other things:
• mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;
• an inability to secure adequate customer commitments to use the acquired systems or facilities;
• an inability to integrate successfully the assets or businesses we acquire;
• the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;
• the diversion of management’s and employees’ attention from other business concerns; and
• unforeseen difficulties operating in new geographic areas or business lines.
If any acquisition eventually proves not to be accretive to our distributable cash flow per unit, it could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Expanding our business by constructing new midstream assets subjects us to risks.
Organic and greenfield growth projects are a significant component of our growth strategy. The development and construction of pipelines and storage facilities involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. The development and construction of pipelines and storage facilities exposes us to construction risks such as failure to meet affiliate and third-party contractual requirements, the lack of available skilled labor, equipment and materials and the inability to obtain necessary approvals and permits from regulatory agencies on a timely basis. These types of projects may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new midstream asset, the construction will occur over an extended period of time, and we will not receive material increases in revenues until the project is placed into service. Moreover, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, liquidity and ability to make distributions.
Certain of our internal growth projects may require regulatory approval from federal and state authorities prior to construction, including any extensions from or additions to our transmission and storage system. The approval process for storage and transportation projects located in the Northeast has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas, including the Marcellus Shale. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions.
If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make quarterly cash distributions may be diminished or our financial leverage could increase. We do not have any commitment with any of our affiliates to provide any direct or indirect financial assistance to us.
In order to expand our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions. We will be required to use cash from our operations or incur borrowings or sell additional common units or other limited partner interests in order to fund our expansion capital expenditures. Using cash from operations will reduce distributable cash flow to our common unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering as well as the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings,
the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.
We do not have any commitment with our general partner or other affiliates, including EQT, to provide any direct or indirect financial assistance to us.
We are subject to numerous hazards and operational risks.
Our business operations are subject to all of the inherent hazards and risks normally incidental to the gathering, compressing, transportation and storage of natural gas. These operating risks include, but are not limited to:
• damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
• inadvertent damage from construction, vehicles, farm and utility equipment;
• uncontrolled releases of natural gas and other hydrocarbons;
• leaks, migrations or losses of natural gas as a result of the malfunction of equipment or facilities and, with respect to storage assets, as a result of undefined boundaries, geologic anomalies, natural pressure migration and wellbore migration;
• ruptures, fires and explosions; and
• other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. The location of certain segments of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. In spite of any precautions taken, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make distributions. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include limitations on our ability to satisfy customer requirements, obligations to provide reservation charge credits to customers in times of constrained capacity, and solicitation of our existing customers by others for potential new projects that would compete directly with our existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations, liquidity and on our ability to make distributions to you.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
We are not fully insured against all risks inherent to our businesses, including environmental accidents that might occur. In addition, we do not maintain business interruption insurance in the type and amount necessary to cover all possible risks of loss. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, liquidity and on our ability to make distributions to you.
EQT currently maintains excess liability insurance that covers EQT’s and its affiliates’, including our, legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability but excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that result in acidic deposition; and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of EQT and its affiliates.
EQT also maintains coverage for itself and its affiliates, including us, for physical damage to assets and resulting business interruption, including damage caused by terrorist acts committed by a U.S. person or interest.
All of EQT’s insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates, and we may elect to self insure a portion of our asset portfolio. The insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. In addition, we share insurance coverage with EQT, for which we will reimburse EQT pursuant to the terms of the omnibus agreement. To the extent EQT experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased.
We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
Our operations are regulated extensively at the federal, state and local levels. Laws, regulations and other legal requirements have increased the cost to plan, design, install, operate and abandon transmission and gathering systems and pipelines. Environmental, health and safety legal requirements govern discharges of substances into the air and water; the management and disposal of hazardous substances and wastes; the clean-up of contaminated sites; groundwater quality and availability; plant and wildlife protection; locations available for pipeline construction; environmental impact studies and assessments prior to permitting; restoration of properties after construction or operations are completed; pipeline safety (including replacement requirements); and work practices related to employee health and safety. Compliance with the laws, regulations and other legal requirements applicable to our businesses may increase our cost of doing business or result in delays due to the need to obtain additional or more detailed governmental approvals and permits. These requirements could also subject us to claims for personal injuries, property damage and other damages. Our failure to comply with the laws, regulations and other legal requirements applicable to our businesses, even if as a result of factors beyond our control, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages.
Laws, regulations and other legal requirements are constantly changing, and implementation of compliant processes in response to such changes could be costly and time consuming. In addition to periodic changes to air, water and waste laws, as well as recent EPA initiatives to impose climate change-based air regulations on industry, the U.S. Congress and various states have been evaluating climate-related legislation and other regulatory initiatives that would further restrict emissions of greenhouse gases, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of burning natural gas). Such restrictions may result in additional compliance obligations with respect to, or taxes on the release, capture and use of, greenhouse gases that could have an adverse effect on our operations.
These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. There is a risk that we may incur costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of wastes and potential emissions and discharges related to our operations. Private parties, including the owners of the properties through which our transmission and storage system or our gathering system pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to require remediation of contamination or enforce compliance with environmental requirements as well as to seek damages for personal injury or property damage. Pursuant to the terms of the omnibus agreement, EQT will indemnify us for certain potential environmental and toxic tort claims, losses and expenses associated with the operation of the assets retained by us and occurring before the closing date of the IPO. However, the maximum liability of EQT for these indemnification obligations
will not exceed $15 million, which may not be sufficient to fully compensate us for such claims, losses and expenses. In addition, changes in environmental laws occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make distributions. We may not be able to recover all or any of these costs from insurance.
Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.
In December 2009, the EPA published its findings that emissions of greenhouse gases (GHGs), present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, the EPA adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates GHG emissions from certain large stationary sources under the Clean Air Act Prevention of Significant Deterioration and Title V permitting programs. The stationary source rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In addition, the EPA expanded its existing GHG emissions reporting rule to include onshore oil and natural gas processing, transmission, storage, and distribution activities beginning in 2012 for emissions occurring in 2011. Congress has also from time to time considered legislation to reduce emissions of GHGs. The adoption of any legislation or regulations that restrict emissions of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the natural gas we transport, store and gather.
Significant portions of our pipeline systems have been in service for several decades. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make distributions.
Significant portions of our transmission and storage system and our gathering system have been in service for several decades. The age and condition of our systems could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our systems could adversely affect our business, financial condition, results of operations, liquidity and our ability to make cash distributions to our unitholders.
We may incur significant costs and liabilities as a result of pipeline integrity management program testing and related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the U.S. Department of Transportation, or DOT, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could harm “high consequence areas,” including high population areas, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators, including us, to:
• perform ongoing assessments of pipeline integrity;
• identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
• maintain processes for data collection, integration and analysis;
• repair and remediate pipelines as necessary; and
• implement preventive and mitigating actions.
Moreover, changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. On January 3, 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which act, among other things, 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 and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. These safety enhancement requirements and other provisions of this act 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 business, financial condition, results of operations, liquidity or ability to make distributions.
On September 25, 2013, PHMSA released a final rule increasing the civil penalty maximums for pipeline safety violations. The rule increased the maximum penalties from $100,000 to $200,000 per day for each violation, and from $1,000,000 to $2,000,000 for a related series of violations. Additionally, PHMSA issued an Advisory Bulletin in May 2012, which advised pipeline operators of changes in annual reporting requirements. The bulletin also advised operators that if they rely on design, construction, inspection, testing or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. In the absence of any such records, the bulletin advised that operators should verify maximum pressures through physical testing or modify/replace facilities to meet the demands of such pressures. As required by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, the Partnership verified its records for all applicable pipeline segments and submitted a report to DOT identifying each pipeline segment for which records were insufficient.
States are generally preempted by federal law in the area of pipeline safety, but state agencies may qualify to assume responsibility for enforcing federal regulations over intrastate pipeline regulations. They may also promulgate additive pipeline safety regulations provided that the state adopts standards that are at least as stringent as the federal standards. Although many of our natural gas facilities fall within a class that is not subject to integrity management requirements, we may incur significant costs and liabilities associated with repair, remediation, preventive or mitigation measures associated with our non-exempt pipelines, particularly our gathering pipelines. This estimate does not include the costs, if any, for repair, remediation, preventive or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. Such costs and liabilities might relate to repair, remediation, preventive or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, should we fail to comply with DOT regulations, we could be subject to penalties and fines. In addition, we may be required to make additional maintenance capital expenditures in the future for similar regulatory compliance initiatives that are not reflected in our forecasted maintenance capital expenditures.
The adoption of legislation relating to hydraulic fracturing and the enactment of severance taxes and impact fees on natural gas wells could cause our current and potential customers to reduce the number of wells they drill in the Marcellus Shale. If drilling reductions are significant, the reductions would have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Our assets are primarily located in the Marcellus Shale fairway in southwestern Pennsylvania and northern West Virginia and a majority of the production that we receive from customers is produced from wells completed using hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays like the Marcellus Shale. Certain federal and state agencies as well as third parties have proposed additional laws and regulations to more closely regulate the hydraulic fracturing process, and legislation has been proposed or is under discussion at both the federal and state levels. We cannot predict whether any such federal or state legislation or regulation will be enacted and, if enacted, how it may affect our operations, but enactment of additional laws or regulations could increase our operating costs.
In 2011, West Virginia adopted legislation that establishes additional regulatory requirements relating to horizontal drilling and hydraulic fracturing. These initiatives could result in additional levels of regulation and permitting of hydraulic fracturing operations, which could cause our customers to experience operational delays, increased operating and compliance costs, restrictions or bans on drilling new wells, and additional regulatory burdens that could make it more difficult or commercially impracticable for our customers to perform hydraulic fracturing, delaying the development of unconventional gas resources from shale formations which are not
commercial without the use of hydraulic fracturing and reducing the volume of natural gas transported through our pipelines.
We are exposed to costs associated with fuel usage and other requirements.
A certain amount of natural gas is utilized in connection with its transportation across a pipeline system and under our contractual arrangements with our customers we are entitled to retain a specified volume of natural gas in order to compensate us for such fuel usage and other requirements. The level of fuel usage and other requirements on our gathering system may exceed the natural gas volumes retained from our customers as compensation for our fuel usage and other requirements pursuant to our contractual agreements. In this case it will be necessary for us to purchase natural gas in the market to make up for the difference, which exposes us to commodity price risk. For the years ended December 31, 2013, 2012 and 2011, our actual commodity usage volumes exceeded the amounts recovered from our gathering customers for which we recognized $3.3 million, $4.0 million and $4.9 million of purchased gas cost as a component of operating and maintenance expense in 2013, 2012 and 2011, respectively. Future exposure to the volatility of natural gas prices as a result of gas imbalances could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Our exposure to direct commodity price risk may increase in the future.
Although we intend to enter into fixed-fee contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in the future that do not provide services primarily based on capacity reservation charges or other fixed fee arrangements and therefore have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of natural gas prices as a result of our future contracts could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way, if such rights-of-way lapse or terminate or if our facilities are not properly located within the boundaries of such rights-of-way. Although many of these rights are perpetual in nature, we occasionally obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. If we were to be unsuccessful in renegotiating rights-of-way, we might have to relocate our facilities. A loss of rights-of-way or a relocation could have a material adverse effect on our business, financial condition, results of operations, liquidity and on our ability to make distributions to you.
Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on our natural gas storage business.
Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for our storage services. The natural gas storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for our services and the rates we are able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, the demand for our storage services and the prices that we will be able to charge for those services may decline.
In addition to volatility and seasonality, an extended period of high natural gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated storage expansion activities. For instance, the settlement approved by the FERC in our most recent rate case included a provision allowing us to recover 7.1 Bcf of storage base gas through our transmission fuel retention percentage. Under the Settlement related
to the PSCT, the transmission fuel retention percentage was reduced from 3.72% to 2.72% effective April 1, 2013. The Settlement also eliminated the tracking mechanism that related to the recovery of 7.1 Bcf of storage base gas. To the extent we need to replace storage base gas under the terms of the Settlement, we may not be able to recover the cost of acquiring such base gas from our customers and will be subject to commodity price risk. An extended period of low natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on our business, financial condition, results of operations, liquidity and ability to make distributions.
Restrictions in our credit facility could adversely affect our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
We maintain a credit facility with a syndicate of lenders. Our credit facility contains various covenants and restrictive provisions that limit our ability to, among other things:
• incur or guarantee additional debt;
• make distributions on or redeem or repurchase units;
• make certain investments and acquisitions;
• incur certain liens or permit them to exist;
• enter into certain types of transactions with affiliates;
• merge or consolidate with another company; and
• transfer, sell or otherwise dispose of assets.
Our credit facility also contains a covenant requiring us to maintain a consolidated leverage ratio of not more than 5.00 to 1.00 (or, after the Partnership obtains an investment grade ratings, not more than 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions). Our ability to meet these covenants can be affected by events beyond our control and we cannot assure our unitholders that we will meet these covenants. In addition, our credit facility contains events of default customary for transactions of this nature, including the occurrence of a change of control (which will occur if EQT fails to control our general partner, we fail to own 100% of Equitrans, L.P., or our general partner fails to be our general partner).
The provisions of our credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our credit facility could result in an event of default, which could enable our lenders to, subject to the terms and conditions of the credit facility, declare any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. The credit facility also has cross default provisions that apply to any other indebtedness we may have with an aggregate principal amount in excess of $15.0 million.
Our future debt levels may limit our flexibility to obtain financing and to pursue other business opportunities.
We have the ability to incur debt, subject to limitations in our credit facility. Our level of debt could have important consequences to us, including the following:
• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
• our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
• we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
• our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our
business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
The credit and risk profile of our general partner and its owner, EQT, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.
The credit and business risk profiles of our general partner and EQT may be factors considered in credit evaluations of us. This is because our general partner, which is owned by EQT, controls our business activities, including our cash distribution policy and growth strategy. Any adverse change in the financial condition of EQT, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness, or a downgrade of EQT’s investment grade credit rating, may adversely affect our credit ratings and risk profile.
If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of our general partner or EQT, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of EQT and its affiliates because of their ownership interest in and control of us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to our unitholders.
Increases in interest rates could adversely impact demand for our storage capacity, our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
There is a financing cost for our customers to store natural gas in our storage facilities. That financing cost is impacted by the cost of capital or interest rates incurred by the customer in addition to the commodity cost of the natural gas in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing natural gas for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.
In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
The amount of cash we have available for distribution to unitholders depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our unitholders.
We rely exclusively on revenues generated from transmission, storage and gathering systems, which are exclusively located in the Appalachian Basin in Pennsylvania and West Virginia. Due to our lack of diversification in assets and geographic location, an adverse development in these businesses or our areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in demand for natural gas, could have a significantly greater impact on our results of operations and distributable cash flow to our unitholders than if we maintained more diverse assets and locations.
For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.
In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act (the JOBS Act). For as long as we remain an “emerging growth company” as defined in the JOBS Act, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our limited partner interests held by non-affiliates at June 30 of any year, or issue more than $1.0 billion of non-convertible debt over a three-year period.
In addition, the JOBS Act provides that an emerging growth company can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have irrevocably elected to “opt out” of this exemption and, therefore, will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.
To the extent that we rely on any of the exemptions available to emerging growth companies, our unitholders will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common units to be less attractive as a result, there may be a less active trading market for our common units and our trading price may be more volatile.
Terrorist or cyber security attacks or threats thereof 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 or cyber security threats coordinated by hackers, whether state-sponsored groups, “hacktivists,” or private individuals. Any terrorist attack or cyber security threat or event at our facilities, those of our customers and, in some cases, those of other pipelines, refineries or terminals could materially and adversely affect our business, financial condition, results of operations, liquidity or ability to make distributions.
Risks Inherent in an Investment in Us
Our general partner and its affiliates, including EQT, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.
EQT indirectly owns and controls our general partner and appointed all of the officers and directors of our general partner. All of the officers and a majority of the directors of our general partner are also officers and/or directors of EQT. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to EQT. Conflicts of interest will arise between EQT and 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 EQT over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
• Neither our partnership agreement nor any other agreement requires EQT to pursue a business strategy that favors us, and the directors and officers of EQT have a fiduciary duty to make these decisions in the best interests of EQT, which may be contrary to our interests. EQT may choose to shift the focus of its investment and growth to areas not served by our assets.
• EQT, as our primary customer, has an economic incentive to cause us not to seek higher tariff rates or gathering fees, even if such higher rates or fees would reflect rates and fees that could be obtained in arm’s-length, third party transaction.
• EQT is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to third parties without first offering us the right to bid for them.
• Our general partner is allowed to take into account the interests of parties other than us, such as EQT, in resolving conflicts of interest.
• All of the officers and a majority of the directors of our general partner are also officers and/or directors of EQT and owe fiduciary duties to EQT. The officers of our general partner also devote significant time to the business of EQT and are compensated by EQT accordingly.
• Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such 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.
• Disputes may arise under our commercial agreements with EQT and its affiliates.
• Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of distributable cash flow.
• Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units.
• Our general partner determines which costs incurred by it are reimbursable by us.
• 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 classify up to $30 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 or general partner units or to our general partner in respect of the incentive distribution rights.
• 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 any of these entities 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 all of the common units not owned by it and its affiliates if they own more than 80% of the common units.
• Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including EQT’s obligations under the omnibus agreement and its commercial agreements with us.
• Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
• Our general partner may transfer its incentive distribution rights without unitholder approval.
• 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 incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
EQT and other affiliates of our general partner are not restricted in their ability to 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 of interests in us. Affiliates of our general partner, including EQT and its other subsidiaries, are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. EQT currently holds interests in, and may make investments in and purchases of, entities that acquire, own and operate other natural gas midstream assets. EQT will be under no obligation to make any acquisition opportunities available to us. Moreover, while EQT may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to accept any offer we might make with respect to such opportunity.
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 EQT. 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 common 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 to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings 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.
In addition, because we intend to 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, and we do not anticipate there being limitations in our credit facility, 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.
The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
Unlike most corporations, we are not required by NYSE rules to have, and we do not intend to have, a majority of independent directors on our general partner’s board of directors or a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
If any of our unitholders are not eligible taxable holders, such unitholders will not be entitled to allocations of income or loss or distributions or voting rights on their common units and their common units will be subject to redemption.
In order to avoid any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by FERC or analogous regulatory body, we have adopted certain requirements regarding those investors who may own our common units. Eligible holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If any of our unitholders are not persons who fit the requirements to be eligible taxable holders, such unitholders will not receive allocations of income or loss or distributions or voting rights on their units and they run the risk of having their units redeemed by us at the market price calculated in accordance with our partnership agreement as of the date of redemption. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different
contractual standards. 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, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision 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 corporate opportunities among us and its affiliates;
• whether to exercise its limited call right;
• whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;
• how to exercise its voting rights with respect to the units it owns;
• whether to elect to reset target distribution levels;
• whether to transfer the incentive distribution rights or any units it owns to a third party; and
• whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to the partnership agreement.
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the above provisions.
Our partnership agreement restricts the remedies available to holders of our common 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, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as specifically provided by our partnership agreement, 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 such decisions are made in good faith;
• 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 (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
- 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;
- approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
- determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
- determined by the board of directors of our general partner to be 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 or the conflicts committee 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 the third and fourth bullets 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 challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce distributable cash flow to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.
Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including EQT, for expenses they incur and payments they make on our behalf. Under the omnibus agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, and insurance expenses. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. Rather, the board of directors of our general partner will be appointed by EQT. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Even if holders of our common units are dissatisfied, they cannot currently remove our general partner without its consent.
Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates, including EQT, owns sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. EQT indirectly owns 43.5% of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined 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 misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of unitholder dissatisfaction with the performance of our general partner in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, 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.
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 the unitholders. Furthermore, our partnership agreement does not restrict the ability of EQT to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.
The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of EQT selling or contributing additional midstream assets to us, as EQT would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
We may issue additional units without unitholder approval, which would dilute our unitholders’ existing ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
• our existing unitholders’ proportionate ownership interest in us will decrease;
• the amount of distributable cash flow on each unit may decrease;
• 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;
• because the amount payable to holders of incentive distribution rights is based on a percentage of the total distributable cash flow, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;
• 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.
EQT may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
EQT indirectly holds an aggregate of 3,443,902 common units and 17,339,718 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. In addition, we have agreed to provide EQT with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.
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 permits our general partner to limit its liability, 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 general partner has a limited call right that may require our unitholders to sell their 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, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their units. EQT indirectly owns approximately 11.3% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), EQT will indirectly own approximately 43.5% of our outstanding common units.
Our general partner, or any transferee holding a majority of the incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
The holder or holders of a majority of the incentive distribution rights, which is currently our general partner, have the right, at any time when there are no subordinated units outstanding and the holders have received incentive distributions at the highest level to which they are entitled (48.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the minimum quarterly distribution and the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. Our general partner has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as our general partner with respect to resetting target distributions.
In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the incentive distribution rights will be entitled to receive, in the aggregate, the number of common units equal to that number of common units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that our general partner or a transferee 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 incentive distribution rights and may therefore desire to be issued common units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels.
Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Our unitholders could be liable for any and all of our obligations as if our unitholders were a general partner if a court or government agency were to determine that:
• we were conducting business in a state but had not complied with that particular state’s partnership statute; or
• our unitholders right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
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, 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 an 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. Transferees of common units are liable both for the obligations of the transferor to make contributions to the partnership that were known to the transferee at the time of transfer and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
We incur increased costs as a result of being a publicly traded partnership.
We had no history operating as a publicly traded partnership prior to the IPO. As a publicly traded partnership, we incur significant legal, accounting and other expenses.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS regarding our qualification as a partnership for tax purposes.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business 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 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), 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 distributable cash flow to our unitholders would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes there would be a material reduction in the anticipated cash flow and after-tax return to our 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.
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our distributable cash flow to our unitholders.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such additional tax on us by a state would reduce the distributable cash flow to our unitholders. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
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 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 the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception 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 any other proposals will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.
Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.
Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
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 distributable cash flow to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the conclusions of our counsel expressed in a prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, 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 distributable cash flow.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell their common units, our unitholders will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of our unitholders allocable share of our net taxable income decrease their tax basis in their
common units, the amount, if any, of such prior excess distributions with respect to the common units our unitholders sell will, in effect, become taxable income to our unitholders if they sell such common units at a price greater than their tax basis in those common units, even if the price our unitholders receive is less than their original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of our unitholders common units, 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 our unitholders sell their common units, our unitholders may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment 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. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If our unitholders are a tax-exempt entity or a non-U.S. person, our unitholders should consult a tax advisor before investing in our common units.
We will treat each purchaser of 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. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from our unitholders sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders tax returns.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes 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 will prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes 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 use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships 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 challenge this 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. Our counsel has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations.
A unitholder whose common units are loaned 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 federal income 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 a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal
income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, 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. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
We will adopt certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
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 technically terminated our 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. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical 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 (and our unitholders could receive two Schedules K-1 if relief was not available) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, the partnership will, among other things, only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
As a result of investing in our common units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and
local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We own property or conduct business in Pennsylvania and West Virginia, each of which currently impose a personal income tax on individuals. Each of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax. It is our unitholders responsibility to file all U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.
See also Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” for further discussion regarding the Partnership’s exposure to market risks, which is incorporated herein by reference.
Item 1B. Unresolved Staff Comments
None.
For a description of material properties, see Item 1, “Business,” which is incorporated herein by reference.
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Partnership. While the amounts claimed may be substantial, the Partnership is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Partnership accrues legal or other direct costs related to loss contingencies when actually incurred. The Partnership has established reserves it believes to be appropriate for pending matters, and after consultation with counsel and giving appropriate consideration to available insurance, the Partnership believes that the ultimate outcome of any matter currently pending against the Partnership will not materially affect its business, financial condition, results of operations, liquidity or ability to make distributions.
Item 4. Mine Safety and Health Administration Data
Not applicable.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The Partnership’s common units have been listed on the New York Stock Exchange (NYSE) under the symbol “EQM” since June 27, 2012. Prior to that, the Partnership’s equity securities were not listed on any exchange or traded on any public trading market. Prior to the IPO, the operations comprising the Partnership were owned by EQT. The following table sets forth the high and low sales prices reflected in the NYSE Composite Transactions of the common units, as reported by the NYSE, as well as the amount of cash distributions declared per quarter from the closing of the IPO through December 31, 2013.
Common Unit Data by Quarter
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2013 |
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2012 |
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Unit Price Range |
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Distributions |
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Unit Price Range |
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Distributions |
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|
|
|
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per Common |
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per Common |
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|
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High |
|
Low |
|
Unit |
|
High |
|
Low |
|
Unit |
|
|
1st Quarter |
$ |
40.74 |
$ |
31.30 |
$ |
0.35 |
|
N/A |
|
N/A |
|
N/A |
|
|
2nd Quarter (a) |
$ |
51.72 |
$ |
35.26 |
$ |
0.37 |
$ |
24.62 |
$ |
22.58 |
|
N/A |
|
|
3rd Quarter |
$ |
51.22 |
$ |
42.16 |
$ |
0.40 |
$ |
30.72 |
$ |
23.70 |
|
N/A |
|
|
4th Quarter |
$ |
59.39 |
$ |
48.45 |
$ |
0.43 |
$ |
31.39 |
$ |
27.70 |
$ |
0.35 |
|
(a) For the second quarter of 2012, reflects post IPO period only.
As of January 31, 2014, there were four unitholders of record of the Partnership’s common units. A cash distribution of $0.46 per common unit was declared on January 23, 2014 and paid on February 14, 2014.
The Partnership has also issued 17,339,718 subordinated units and 975,686 general partner units, for which there is no established public trading market. All of the subordinated units are held by an affiliate of the Partnership’s general partner. The general partner and its affiliates receive quarterly distributions on these units only after sufficient distributions have been paid to the common units. Set forth below under “Distributions of Available Cash” is a summary of the significant provisions of the Partnership’s partnership agreement that relate to distributions of available cash, minimum quarterly distributions and incentive distribution rights.
Market Repurchases
The Partnership did not repurchase any of its common units during 2013.
Distributions of Available Cash
General
The Partnership’s partnership agreement requires that, within 45 days after the end of each quarter, the Partnership distribute all of its available cash (described below) to unitholders of record on the applicable record date.
Available Cash
Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
• less, the amount of cash reserves established by the Partnership’s general partner to:
• provide for the proper conduct of the Partnership’s business (including reserves for future capital expenditures, anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);
• comply with applicable law, any of the Partnership’s debt instruments or other agreements; or
• provide funds for distributions to the Partnership’s unitholders and to the Partnership’s general partner for any one or more of the next four quarters (provided that the Partnership’s general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent the Partnership from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);
• plus, if the Partnership’s 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.
Subordinated Units
All subordinated units are held by an affiliate of the Partnership’s general partner. The Partnership’s partnership agreement provides that, during the period of time referred to as the “subordination period,” the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.35 per common unit (the minimum quarterly distribution, as defined in the Partnership’s partnership agreement) plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to distribute the minimum quarterly distribution to the common units. The subordination period will end and the subordinated units will convert to common units on a one-for-one basis when certain distribution requirements, as defined in the Partnership’s partnership agreement, have been met.
Incentive Distribution Rights
All incentive distribution rights are held by the Partnership’s general partner. Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels described below have been achieved. The Partnership’s general partner may transfer the incentive distribution rights separately from its general partner interest, subject to restrictions in the Partnership’s partnership agreement.
The following discussion assumes that the Partnership’s general partner continues to own both its 2.0% general partner interest and the incentive distribution rights.
If for any quarter:
• the Partnership has distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
• the Partnership has distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;
then, the Partnership will distribute any additional available cash from operating surplus for that quarter among the unitholders and the Partnership’s general partner in the following manner:
|
|
|
Total Quarterly |
|
Marginal Percentage Interest in |
| ||
|
|
|
Distribution per Unit |
|
Distributions |
| ||
|
|
|
Target Amount |
|
Unitholders |
|
General Partner |
|
|
Minimum Quarterly Distribution |
|
$0.3500 |
|
98.0% |
|
2.0% |
|
|
First Target Distribution |
|
Above $0.3500 up to $0.4025 |
|
98.0% |
|
2.0% |
|
|
Second Target Distribution |
|
Above $0.4025 up to $0.4375 |
|
85.0% |
|
15.0% |
|
|
Third Target Distribution |
|
Above $0.4375 up to $0.5250 |
|
75.0% |
|
25.0% |
|
|
Thereafter |
|
Above $0.5250 |
|
50.0% |
|
50.0% |
|
When these incentive distributions are made to the general partner, more available cash proportionally is allocated to the general partner than to holders of common and subordinated units. In connection with the
Partnership’s cash distribution paid on February 14, 2014, EQT received approximately $0.6 million related to its incentive distribution rights.
Equity Compensation Plans
The information relating to the Partnership’s equity compensation plans required by Item 5 is included in Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” of this Form 10-K.
Item 6. Selected Financial Data
The following selected financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8, “Financial Statements and Supplementary Data” of this Form 10-K.
The Partnership closed its IPO on July 2, 2012. Equitrans is a Pennsylvania limited partnership and the predecessor for accounting purposes of the Partnership. For periods prior to the IPO, the following selected financial data reflect the assets, liabilities and results of operations of Equitrans presented on a carve-out basis (excluding the financial position and results of operations of the Big Sandy Pipeline as described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Form 10-K). For periods beginning at or following the IPO, they include the Partnership and its consolidated subsidiaries. Additionally, as discussed below, the Partnership’s consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of Sunrise, which was merged into the Partnership on July 22, 2013, as the transaction was a transfer between entities under common control. The selected financial data covering periods prior to the closing of the IPO and prior to the Sunrise Merger may not necessarily be indicative of the actual results of operations had those contributed entities been operated together during those periods.
|
|
|
As of and for the years ended December 31, |
| ||||||||
|
|
|
2013 |
|
2012 |
|
2011 |
|
2010 |
|
2009 |
|
|
Statements of Consolidated Operations |
|
|
|
(Thousands, except per share amounts) |
|
|
| ||||
|
|
|
|
|
|
|
|
| ||||
|
Total operating revenues |
$ |
185,891 |
$ |
136,910 |
$ |
109,613 |
$ |
91,600 |
$ |
80,057 |
|
|
Operating income |
$ |
114,250 |
$ |
75,151 |
$ |
54,620 |
$ |
37,937 |
$ |
28,704 |
|
|
Net income |
$ |
109,767 |
$ |
63,122 |
$ |
32,589 |
$ |
19,241 |
$ |
14,031 |
|
|
Net income per limited partner unit (a): |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
2.47 |
$ |
1.03 |
|
N/A |
|
N/A |
|
N/A |
|
|
Diluted |
$ |
2.46 |
$ |
1.03 |
|
N/A |
|
N/A |
|
N/A |
|
|
Cash distributions paid per limited partner unit |
$ |
1.55 |
$ |
0.35 |
|
N/A |
|
N/A |
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
$ |
913,013 |
$ |
753,637 |
$ |
546,542 |
$ |
415,001 |
$ |
386,682 |
|
|
Long-term debt |
$ |
— |
$ |
— |
$ |
135,235 |
$ |
135,235 |
$ |
57,107 |
|
|
Long-term lease obligation |
$ |
133,733 |
$ |
— |
$ |
— |
$ |
— |
$ |
— |
|
(a) Net income attributable to periods prior to the IPO and net income attributable to Sunrise for periods prior to July 22, 2013 is not allocated to the limited partners for purposes of calculating net income per limited partner unit. See Note 1 to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
References in the following discussion and analysis to the “Partnership,” when used for periods prior to the IPO, refer to Equitrans. References in the following discussion and analysis to the “Partnership,” when used for periods beginning at or following the IPO, refer collectively to the Partnership and its consolidated subsidiaries. As discussed below, the Partnership’s consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of Sunrise, which was merged into the Partnership on July 22, 2013, as the transaction was a transfer between entities under common control. References in the following discussion and analysis to ‘‘EQT’’ refer collectively to EQT Corporation and its consolidated subsidiaries.
Executive Overview
On July 15, 2013, the Partnership and Equitrans entered into an Agreement and Plan of Merger with EQT and Sunrise, a wholly owned subsidiary of EQT and the owner of the Sunrise Pipeline. Effective July 22, 2013, Sunrise merged with and into Equitrans, with Equitrans continuing as the surviving company. Upon closing, the Partnership paid EQT consideration of $540 million, consisting of a $507.5 million cash payment, 479,184 Partnership common units and 267,942 Partnership general partner units. Prior to the Sunrise Merger, Equitrans entered into a precedent agreement with a third party for firm transportation service on the Sunrise Pipeline over a twenty-year term (the “Precedent Agreement”). Pursuant to the Agreement and Plan of Merger, the Partnership paid additional consideration of $110 million to EQT in January 2014 following the effectiveness of the transportation agreement contemplated by the Precedent Agreement.
Prior to the Sunrise Merger, the Partnership operated the Sunrise Pipeline as part of its transmission and storage system under a lease agreement with EQT. The lease was a capital lease under GAAP and, as a result, revenues and expenses associated with Sunrise were included in the Partnership ‘s financial statements. However, the monthly lease payment to EQT offset the impact of Sunrise operations on the Partnership’s adjusted EBITDA and distributable cash flow. Effective as of the closing of the Sunrise Merger on July 22, 2013, the lease agreement was terminated. As the transaction was a transfer between entities under common control, the Partnership’s historical consolidated financial statements have been retrospectively recast to reflect the results attributable to Sunrise for all periods presented.
On July 22, 2013, the Partnership completed an underwritten public offering of 12,650,000 common units. Net proceeds from the offering were used to finance the cash consideration paid to EQT in connection with the Sunrise Merger. Following the offering and Sunrise Merger, EQT retained a 44.6% equity interest in the Partnership, which includes 3,443,902 common units, 17,339,718 subordinated units and 975,686 general partner units. The Partnership received net proceeds of approximately $529 million from the offering after deducting the underwriters’ discount and offering expenses of approximately $21 million.
On December 17, 2013, the Partnership entered into a capital lease with EQT for the AVC facilities. Under the lease, the Partnership operates the AVC facilities as part of its transmission and storage system under the rates, terms and conditions of its FERC-approved tariff. The AVC facilities are strategically located to connect Marcellus Shale supply and demand and include an approximately 200 mile pipeline that interconnects with the Partnership’s transmission and storage system. The AVC facilities provide 450 BBtu per day of additional firm capacity to the Partnership’s system and are supported by 4 associated natural gas storage reservoirs with approximately 260 MMcf per day of peak withdrawal capability and 15 Bcf of working gas capacity. Of the total 15 Bcf of working gas capacity, the Partnership leases and operates 13 Bcf of working gas capacity.
The Partnership reported net income of $109.8 million in 2013 compared with $63.1 million in 2012. The increase was primarily related to an increase in transmission and storage revenues of $53.1 million primarily due to increased firm transmission service and increased system throughput, which were driven by production development in the Marcellus Shale partly offset by a $9.9 million increase in operating expenses consistent with the overall growth of the transmission system.
In 2013, net income per limited partner unit was $2.47 and diluted net income per limited partner unit was $2.46. For the year ended December 31, 2013, adjusted EBITDA was $119.5 million and distributable cash flow was $101.4 million. The Partnership paid cash distributions of $1.55 per limited partner unit during the year ended December 31, 2013 and declared a cash distribution to unitholders of $0.46 on January 23, 2014. For a discussion of
the non-GAAP financial measures adjusted EBITDA and distributable cash flow, please read the sections titled “Non-GAAP Financial Measures” and “Reconciliation of Non-GAAP Measures.”
The Partnership reported net income of $63.1 million in 2012 compared with $32.6 million in 2011. The increase was primarily related to an increase in operating income of $20.5 million, an increase in other income and lower expenses for interest and taxes. Transmission and storage revenues increased by $27.1 million primarily due to increased firm transmission service and increased system throughput, which were driven by production development in the Marcellus Shale. Total operating expenses increased $6.8 million, consistent with the overall growth of the transmission system.
Consolidated Results of Operations
|
|
|
Years Ended December 31, |
| ||||||||
|
|
|
2013 |
|
2012 |
|
% |
|
2011 |
|
% |
|
|
|
|
(Thousands, other than per unit) |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Transmission and storage revenues |
$ |
173,881 |
$ |
120,797 |
|
43.9 |
$ |
93,707 |
|
28.9 |
|
|
Gathering revenues |
|
12,010 |
|
16,113 |
|
(25.5) |
|
15,906 |
|
1.3 |
|
|
Total operating revenues |
|
185,891 |
|
136,910 |
|
35.8 |
|
109,613 |
|
24.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance |
|
28,954 |
|
29,405 |
|
(1.5) |
|
26,221 |
|
12.1 |
|
|
Selling, general and administrative |
|
21,497 |
|
16,614 |
|
29.4 |
|
17,302 |
|
(4.0) |
|
|
Depreciation and amortization |
|
21,190 |
|
15,740 |
|
34.6 |
|
11,470 |
|
37.2 |
|
|
Total operating expenses |
|
71,641 |
|
61,759 |
|
16.0 |
|
54,993 |
|
12.3 |
|
|
Operating income |
|
114,250 |
|
75,151 |
|
52.0 |
|
54,620 |
|
37.6 |
|
|
Other income, net |
|
1,242 |
|
8,228 |
|
(84.9) |
|
3,826 |
|
115.1 |
|
|
Interest expense, net |
|
1,672 |
|
2,944 |
|
(43.2) |
|
5,050 |
|
(41.7) |
|
|
Income before income taxes |
|
113,820 |
|
80,435 |
|
41.5 |
|
53,396 |
|
50.6 |
|
|
Income tax expense |
|
4,053 |
|
17,313 |
|
(76.6) |
|
20,807 |
|
(16.8) |
|
|
Net income |
$ |
109,767 |
$ |
63,122 |
|
73.9 |
$ |
32,589 |
|
93.7 |
|
|
Net income per limited partner unit |
|
|
|
|
|
|
|
|
|
|
|
|
Basic (1) |
$ |
2.47 |
$ |
1.03 |
|
N/M(2) |
|
N/A |
|
N/A |
|
|
Diluted (1) |
$ |
2.46 |
$ |
1.03 |
|
N/M(2) |
|
N/A |
|
N/A |
|
|
Adjusted EBITDA (1) |
$ |
119,510 |
$ |
39,996 |
|
N/M(2) |
|
N/A |
|
N/A |
|
|
Distributable cash flow (1) |
$ |
101,371 |
$ |
26,415 |
|
N/M(2) |
|
N/A |
|
N/A |
|
|
| |||||||||||
(1) Presented for the post-IPO period only. For an explanation of the non-GAAP financial measures adjusted EBITDA and distributable cash flow and a reconciliation of these measures to their most directly comparable GAAP financial measures, please read the sections below titled “Non-GAAP Financial Measures” and “Reconciliation of Non-GAAP Measures.”
(2) Not meaningful data as the amounts presented are for the year ended December 31, 2013 compared to the post-IPO period of the six months ended December 31, 2012.
Business Segment Results
Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and is subject to evaluation by the chief operating decision maker in deciding how to allocate resources. Interest and other income are managed on a consolidated basis. The Partnership has presented each segment’s operating income and various operational measures in the sections below. Management believes that presentation of this information provides useful information to management and investors regarding the financial condition, results of operations and trends of segments. The Partnership has reconciled each segment’s operating income to the Partnership’s consolidated operating income and net income in Note 3 to the Consolidated Financial Statements.
|
|
|
Years Ended December 31, |
| ||||||||
|
|
|
2013 |
|
2012 |
|
% |
|
2011 |
|
% |
|
|
SEGMENT FINANCIAL DATA – TRANSMISSION AND STORAGE |
|
(Thousands, other than per day amounts) |
| ||||||||
|
Operating revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues – affiliate |
$ |
135,998 |
$ |
95,849 |
|
41.9 |
$ |
76,449 |
|
25.4 |
|
|
Operating revenues – third party |
|
37,883 |
|
24,948 |
|
51.8 |
|
17,258 |
|
44.6 |
|
|
Total operating revenues |
|
173,881 |
|
120,797 |
|
43.9 |
|
93,707 |
|
28.9 |
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance |
|
15,041 |
|
15,191 |
|
(1.0) |
|
11,677 |
|
30.1 |
|
|
Selling, general and administrative |
|
15,567 |
|
11,578 |
|
34.5 |
|
12,274 |
|
(5.7) |
|
|
Depreciation and amortization |
|
18,323 |
|
12,901 |
|
42.0 |
|
8,850 |
|
45.8 |
|
|
Total operating expenses |
|
48,931 |
|
39,670 |
|
23.3 |
|
32,801 |
|
20.9 |
|
|
Operating income |
$ |
124,950 |
$ |
81,127 |
|
54.0 |
$ |
60,906 |
|
33.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEGMENT OPERATIONAL DATA –TRANSMISSION AND STORAGE |
|
|
|
|
|
|
|
|
|
|
|
|
Transmission pipeline throughput (BBtu per day) |
|
1,146 |
|
606 |
|
89.1 |
|
397 |
|
52.6 |
|
|
Capital expenditures |
$ |
77,989 |
$ |
188,143 |
|
(58.5) |
$ |
131,902 |
|
42.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEGMENT FINANCIAL DATA – GATHERING |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues – affiliate |
$ |
6,439 |
$ |
10,331 |
|
(37.7) |
$ |
10,107 |
|
2.2 |
|
|
Operating revenues – third party |
|
5,571 |
|
5,782 |
|
(3.6) |
|
5,799 |
|
(0.3) |
|
|
Total operating revenues |
|
12,010 |
|
16,113 |
|
(25.5) |
|
15,906 |
|
1.3 |
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance |
|
13,913 |
|
14,214 |
|
(2.1) |
|
14,544 |
|
(2.3) |
|
|
Selling, general and administrative |
|
5,930 |
|
5,036 |
|
17.8 |
|
5,028 |
|
0.2 |
|
|
Depreciation and amortization |
|
2,867 |
|
2,839 |
|
1.0 |
|
2,620 |
|
8.4 |
|
|
Total operating expenses |
|
22,710 |
|
22,089 |
|
2.8 |
|
22,192 |
|
(0.5) |
|
|
Operating loss |
$ |
(10,700) |
$ |
(5,976) |
|
79.1 |
$ |
(6,286) |
|
(4.9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEGMENT OPERATIONAL DATA –GATHERING |
|
|
|
|
|
|
|
|
|
|
|
|
Gathering volumes (BBtu per day) |
|
58 |
|
78 |
|
(25.6) |
|
78 |
|
0.0 |
|
|
Capital expenditures |
$ |
5,031 |
$ |
5,379 |
|
(6.5) |
$ |
3,929 |
|
36.9 |
|
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Total operating revenues were $185.9 million for the year ended December 31, 2013 compared to $136.9 million for the year ended December 31, 2012. The increase was a result of a $53.1 million increase in transmission and storage operating revenues partly offset by a decrease of $4.1 million in gathering revenues.
Transmission and storage revenues increased as a result of higher firm transmission contracted capacity and increased system throughput as compared to the prior year. This includes $44.8 million of revenue associated with increased reservation fees under firm contracts and $10.9 million of fees associated with firm usage charges and transported volumes in excess of firm capacity. These increases were primarily driven by activity related to the Sunrise Pipeline and the Blacksville compressor station, which were completed in July and September 2012, respectively, as well as the addition of the AVC facilities in December 2013. This increased activity is a result of increased production development in the Marcellus Shale. The average daily transmission throughput increased by 540 BBtu per day during the year ended December 31, 2013 compared to the year ended December 31, 2012. These increases were partly offset by a decrease in storage and parking revenues of $3.2 million.
The average daily volumes gathered decreased 20 BBtu, or 26%, compared to the prior year, which resulted in reduced gathering revenues. The decrease in gathered volumes was primarily the result of affiliates utilizing direct interconnects to the Partnership’s transmission system.
Operating expenses totaled $71.6 million for the year ended December 31, 2013 compared to $61.8 million for the year ended December 31, 2012. The increase in operating expenses was due to a $5.4 million increase in depreciation and amortization expense and a $4.9 million increase in selling, general and administrative expense, which were slightly offset by a small decrease in operating and maintenance expense.
The increase in depreciation and amortization expense was in transmission and storage as a result of increased investment in transmission infrastructure, most notably a full year of depreciation in 2013 for both the Sunrise Pipeline and the Blacksville compressor station.
The increase in selling, general and administrative expense resulted from several items, including $2.4 million of lower reserve adjustments in 2013 compared to 2012 from: $1.8 million of lower adjustments for the collectability of a long-term regulatory asset and a $0.6 million reduction to a legal reserve in the prior year. Additionally, in 2013 personnel costs increased $1.3 million and the Partnership incurred $0.7 million of transaction costs in connection with the Sunrise Merger.
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Total operating revenues were $136.9 million for the year ended December 31, 2012 compared to $109.6 million for the year ended December 31, 2011. The increase was primarily related to a $27.1 million increase in transmission and storage operating revenues. Gathering revenues were essentially flat year over year.
Transmission and storage revenues increased as a result of increased firm transmission service and increased system throughput. This includes $12.2 million of reservation fees and usage charges under firm contracts on the Sunrise Pipeline, $11.8 million of fees associated with transported volumes in excess of firm capacity and increased reservation fees and usage charges under other firm contracts, which includes contracts for the Blacksville Compressor station. These increases resulted from increased production development in the Marcellus Shale. The average daily transmission throughput increased by 209 BBtu per day during the year ended December 31, 2012 compared to the year ended December 31, 2011. These increases were partly offset by a decrease in storage and parking revenues.
Operating expenses totaled $61.8 million for the year ended December 31, 2012 compared to $55.0 million for the year ended December 31, 2011. The increase in operating expenses was due to a $4.3 million increase in depreciation and amortization expense and a $3.2 million increase in operating and maintenance expense, which were slightly offset by a $0.7 million decrease in selling, general and administrative expense.
The increase in depreciation and amortization expense was primarily in transmission and storage as a result of increased investment in transmission infrastructure, including the Sunrise Pipeline and the Blacksville compressor station which were both placed in service in 2012.
The increase in operating and maintenance expense resulted from a $3.5 million increase in transmission and storage expenses partly offset by a small decline in gathering operating and maintenance expense. Transmission and storage expenses increased primarily as a result of increased amortization of pipeline safety costs of $1.4 million, additional operating costs of $0.9 million associated with operating the Sunrise Pipeline and non-income based taxes of $0.5 million. The decrease in gathering expense primarily resulted from lower purchased gas costs of $0.9 million which was partly offset by increased repairs and maintenance expenses of $0.7 million. Fuel usage and other requirements on the gathering system have historically exceeded the natural gas retained from the Partnership’s gathering customers as compensation for its fuel usage and other requirements. Purchased gas costs were recorded for the difference. The decline in purchased gas costs during 2012 was primarily the result of lower prices, partly offset by increased volumes lost due to higher system pressures.
In the transmission and storage segment, selling, general and administrative expenses decreased by $0.7 million primarily due to a $2.5 million reduction of a reserve on the collectability of long-term regulatory assets and a $0.6 million reduction to a legal reserve. The regulatory reserve was established for the recovery of base storage gas. These expense reductions were partly offset by increased expenses associated with being a publicly traded partnership of $1.4 million and $1.0 million due to additional costs attributable to the Sunrise Pipeline.
Other Income Statement Items
Other income primarily represents the equity portion of AFUDC which generally increases during periods of increased construction and decreases during periods of reduced construction of regulated assets. The decrease of $7.0 million in other income for the year ended December 31, 2013 when compared to the year ended December 31, 2012 primarily resulted from a decrease in applicable construction expenditures on regulated projects as the Sunrise Pipeline and Blacksville compressor station projects were turned-in-line during 2012. The increase in other income for the year ended December 31, 2012 when compared to the year ended December 31, 2011 primarily resulted from an increase in applicable construction expenditures in connection with the Sunrise Pipeline project.
Interest expense for the year ended December 31, 2013 was $1.7 million compared to $2.9 million for the year ended December 31, 2012. For the year ended December 31, 2013, interest expense primarily consisted of commitment fees paid to maintain availability under the Partnership’s credit facility and interest related to the AVC capital lease. For the year ended December 31, 2012, interest expense primarily related to intercompany debt which was repaid in June 2012. Interest expense for the year ended December 31, 2012 was $2.9 million compared to $5.1 million for the year ended December 31, 2011. The decrease primarily related to the repayment of intercompany debt in June 2012 prior to the IPO.
Income tax expense was $4.1 million, $17.3 million and $20.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. From and after the IPO, the Partnership is not subject to U.S. federal and state income taxes. Income earned prior to July 2, 2012 was subject to federal and state income tax. As previously noted, the Sunrise Merger on July 22, 2013 was a transfer between entities under common control for which the financial statements of the Partnership have been retrospectively recast to reflect the combined entities. Accordingly, the income tax effects associated with Sunrise’s operations prior to the Sunrise Merger are reflected in the consolidated financial statements as Sunrise was previously part of EQT’s consolidated federal tax return. The decreases in income tax expense resulted from these changes in tax status.
Non-GAAP Financial Measures
The Partnership defines adjusted EBITDA as net income plus net interest expense, depreciation and amortization expense, income tax expense (if applicable), non-cash long-term compensation expense and other non-cash adjustments (if applicable) less other income and capital lease payments prior to acquisition of the underlying assets. As used herein, the Partnership defines distributable cash flow as adjusted EBITDA less cash interest, ongoing maintenance capital expenditures and potentially reimbursable maintenance capital expenditures plus reimbursable maintenance capital expenditures to be reimbursed by EQT. Adjusted EBITDA and distributable cash
flow are non-GAAP supplemental financial measures that management and external users of the Partnership’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, use to assess:
• the Partnership’s operating performance as compared to other publicly traded partnerships in the midstream energy industry without regard to historical cost basis or, in the case of adjusted EBITDA, financing methods;
• the ability of the Partnership’s assets to generate sufficient cash flow to make distributions to the Partnership’s unitholders;
• the Partnership’s ability to incur and service debt and fund capital expenditures; and
• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
The Partnership believes that adjusted EBITDA and distributable cash flow provide useful information to investors in assessing the Partnership’s financial condition and results of operations. Adjusted EBITDA and distributable cash flow should not be considered as alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect net income and net cash provided by operating activities. Additionally, because adjusted EBITDA and distributable cash flow may be defined differently by other companies in its industry, the Partnership’s definition of adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Distributable cash flow should not be viewed as indicative of the actual amount of cash that the Partnership has available for distributions from operating surplus or that the Partnership plans to distribute.
Reconciliation of Non-GAAP Measures
The following table presents a reconciliation of adjusted EBITDA and distributable cash flow with net income and net cash provided by operating activities, the most directly comparable GAAP financial measures.
|
|
|
Years Ended December 31, |
| ||
|
|
|
2013
|
|
2012 (1)
|
|
|
|
|
(Thousands) |
| ||
|
Net income |
$ |
109,767 |
$ |
40,360 |
|
|
Add: |
|
|
|
|
|
|
Interest expense, net |
|
1,672 |
|
191 |
|
|
Depreciation and amortization |
|
21,190 |
|
9,532 |
|
|
Income tax expense |
|
4,053 |
|
3,822 |
|
|
Non-cash long-term compensation expense |
|
981 |
|
535 |
|
|
Non-cash adjustments |
|
(680) |
|
(2,508) |
|
|
Less: |
|
|
|
|
|
|
Other income, net |
|
(1,242) |
|
(1,600) |
|
|
Capital lease payments prior to acquisition |
|
(16,231) |
|
(10,336) |
|
|
Adjusted EBITDA |
$ |
119,510 |
$ |
39,996 |
|
|
Less: |
|
|
|
|
|
|
Cash interest |
|
(939) |
|
(445) |
|
|
Ongoing maintenance capital expenditures(2) |
|
(13,192) |
|
(9,753) |
|
|
Potentially reimbursable P&A maintenance capital expenditures(3) |
|
(566) |
|
(1,585) |
|
|
Potentially reimbursable bare steel maintenance capital expenditures(3) |
|
(6,574) |
|
(6,042) |
|
|
Add: |
|
|
|
|
|
|
Reimbursable P&A maintenance capital expenditures(3) |
|
566 |
|
1,585 |
|
|
Reimbursable bare steel maintenance capital expenditures(3) |
|
2,566 |
|
2,659 |
|
|
Distributable cash flow |
$ |
101,371 |
$ |
26,415 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
$ |
121,335 |
$ |
72,466 |
|
|
Adjustments: |
|
|
|
|
|
|
Interest expense, net |
|
1,672 |
|
191 |
|
|
Current tax expense (benefit) |
|
4,315 |
|
(36,010) |
|
|
Capital lease payments prior to acquisition |
|
(16,231) |
|
(10,336) |
|
|
Other, including changes in working capital |
|
8,419 |
|
13,685 |
|
|
Adjusted EBITDA |
$ |
119,510 |
$ |
39,996 |
|
|
|
|
|
|
|
|
(1) Presented for post-IPO period only.
(2) Ongoing maintenance capital expenditures are expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, the Partnership’s operating capacity or operating income.
(3) EQT has reimbursement obligations to the Partnership for certain capital expenditures for plugging and abandonment (P&A) of natural gas wells and bare steel pipe replacement. For further explanation of these reimbursable maintenance capital expenditures, see the section below titled “Capital Requirements.”
Adjusted EBITDA was $119.5 million for the year ended December 31, 2013 compared to $40.0 million for the six months ended December 31, 2012. The increase was primarily a result of a full year of post-IPO operations and increased transmission and storage operating revenues related to production development in the Marcellus Shale. Distributable cash flow was $101.4 million for the year ended December 31, 2013 compared to $26.4 million for the six months ended December 31, 2012. The increase was mainly attributable to the increase in adjusted EBITDA for the full year, which was slightly offset by increased maintenance capital expenditures for the full year.
Outlook
The Partnership’s principal business objective is to increase the quarterly cash distributions that it pays to its unitholders over time while ensuring the ongoing growth of its business. The Partnership believes that it is well-positioned to achieve growth based on the combination of its relationship with EQT and its strategically located assets, which cover portions of the Marcellus Shale that lack substantial natural gas pipeline infrastructure. As production increases in the Partnership’s areas of operations, the Partnership believes it will have a competitive advantage in attracting volumes to its system through relatively low-cost capacity expansions. Additionally, the Partnership may acquire additional midstream assets from EQT, or pursue asset acquisitions from third parties. Should EQT choose to pursue midstream asset sales, it is under no contractual obligation to offer the assets to the Partnership.
In the near term, the Partnership expects that the following internal transmission and storage expansion projects also will allow it to capitalize on increased drilling activity by EQT and other third-party producers.
• Jefferson Compressor Station Expansion Project. This project involves expanding the Jefferson compressor station to provide approximately 550 BBtu per day of incremental capacity on the Sunrise Pipeline system. When complete, the project is expected to more than double the existing throughput capacity on the Sunrise Pipeline of approximately 400 BBtu per day. The expansion, which is expected to cost approximately $30 million, is expected to be placed into service in the third quarter of 2014. Approximately $20 million is expected to be spent in 2014 related to this project.
• Transmission Expansion (Antero Project). The Partnership entered into two separate agreements with Antero Resources for firm transportation services on the Partnership’s transmission system. Under each agreement, the Partnership will ultimately provide 100 BBtu per day of firm transmission capacity on the transmission system for a combined total of 200 BBtu per day. As part of the agreements, the Partnership expects to spend approximately $55 million on two separate transmission expansion projects in northern West Virginia. The West-Side Expansion will add 100 BBtu per day of transmission capacity at an estimated cost of $26 million and is expected to be in full service by year-end 2014. The East-Side Expansion will add 100 BBtu per day of transmission capacity at an estimated cost of $29 million and is expected to be in full service by mid-year 2015. The agreements are primarily fixed-fee, demand based contracts with a 10-year term commencing on the applicable project’s full 100 BBtu per day in-service date. The Partnership expects to spend approximately $30 million on the two projects in 2014, with the remaining $25 million to be spent in 2015.
• Transmission and Gathering Expansion (Range Resources Project). The Partnership entered into definitive agreements with a subsidiary of Range Resources Corporation to provide gathering, compression, and transmission services in southwestern Pennsylvania. In 2014, the Partnership expects to invest approximately $30 million in gathering infrastructure and $25 million in a transmission expansion project in conjunction with the agreements. The transmission expansion will add approximately 100 BBtu per day of capacity to the Partnership’s transmission system and is expected to be in service in the fourth quarter of 2014. The agreements include a fee-based 10-year minimum volume commitment for gathering and transmission services.
In 2014, the Partnership plans to spend approximately $135 - 140 million to increase transmission capacity by 750 BBtu per day. The Partnership’s future expansion capital expenditures may vary significantly from period to period based on the available investment opportunities. Maintenance related capital expenditures are also expected to vary quarter to quarter. The Partnership expects to fund future capital expenditures primarily through cash on
hand, cash generated from operations, availability under the Partnership’s credit facility, debt offerings and the issuance of additional partnership units.
Capital Resources and Liquidity
The Partnership’s principal liquidity requirements are to finance its operations, fund capital expenditures and acquisitions, make cash distributions and satisfy any indebtedness obligations. The Partnership’s ability to meet these liquidity requirements will depend on its ability to generate cash in the future. From and after the IPO, the Partnership’s available sources of liquidity include cash generated from operations, borrowing under the Partnership’s credit facility, cash on hand, debt offerings and issuances of additional partnership units.
Prior to the IPO, the Partnership’s primary sources of liquidity included cash generated from operations and cash contributions provided by EQT. The Partnership also participated in EQT’s cash management program prior to the IPO, whereby EQT swept cash balances residing in the Partnership’s bank accounts on a periodic basis. Prior to the IPO, capital expenditures were funded through amounts due to EQT. Subsequent to the IPO, affiliate payables and receivables are settled monthly and are classified as operating activities.
Operating Activities
Net cash provided by operating activities during 2013 was $121.3 million compared to $128.6 million for 2012. The slight decrease was driven by the 2012 cash receipt from EQT related to its use of Sunrise’s depreciation deductions prior to the Sunrise Merger when Sunrise was included in the consolidated tax return of EQT. This was offset by increases in transmission and storage operating receipts due to increased firm transmission service and fees associated with transported volumes in excess of firm capacity related to production development in the Marcellus Shale.
Net cash provided by operating activities during 2012 was $128.6 million compared to $47.6 million for 2011. The increase was primarily a result of an increase in transmission and storage operating revenues due to increased firm transmission service and fees associated with transported volumes in excess of firm capacity related to production development in the Marcellus Shale. Additionally in 2012 there was a cash receipt from EQT related to its use of Sunrise’s depreciation deductions prior to the Sunrise Merger when Sunrise was included in the consolidated tax return of EQT. These increases were partly offset by the distribution to EQT of approximately $12.2 million of trade and other accounts receivable prior to the initial public offering. Proceeds from the offering of $12.2 million were retained to replenish working capital and are reflected in the financing activities.
Investing Activities
Cash flows used in investing activities totaled $83.0 million for 2013 as compared to $193.5 million for 2012. The 2013 capital expenditures primarily related to the Low Pressure East expansion and Jefferson compressor station expansion projects. The 2012 capital expenditures primarily related to the Sunrise Pipeline and Blacksville Compressor station projects, which were completed in the third quarter of 2012.
Cash flows used in investing activities totaled $193.5 million for 2012 as compared to $135.8 million for 2011. The increase in capital expenditures was primarily attributable to the timing of expenditures associated with the Sunrise Pipeline and the Blacksville Compressor station projects.
See further discussion of capital expenditures in the “Capital Requirements” section below.
Financing Activities
Cash flows used in financing activities totaled $70.0 million for 2013 as compared to $115.0 million of cash flows provided by financing activities for the same period of 2012. In July 2013, the Partnership received net proceeds from its equity offering of approximately $529.4 million, after deducting the underwriters’ discount and offering expenses. These funds were used to pay Sunrise Merger consideration to EQT of $507.5 million in July 2013, cash distributions to unitholders of $66.2 million and Sunrise pre-merger distributions to EQT of $31.4 million.
Cash flows provided by financing activities totaled $115.0 million for 2012 as compared to $73.9 million for the same period of 2011. In 2012, the Partnership received net proceeds from the initial public offering of approximately $276.8 million, after deducting the underwriters’ discount and offering expenses. Approximately $230.9 million of the proceeds were distributed to EQT, $12.0 million was retained by the Partnership to replenish amounts distributed by Equitrans to EQT prior to the IPO, $32.0 million was retained by the Partnership to pre-fund certain maintenance capital expenditures and $1.9 million was used by the Partnership to pay credit facility origination fees associated with its credit facility described below. During the fourth quarter of 2012, the Partnership made its first cash distribution to unitholders of approximately $12.4 million.
Prior to the IPO, the Partnership had financing cash inflows of $276.5 million for capital contributions from EQT and financing cash outflows of $10.2 million for distributions paid to EQT, $49.7 million related to reimbursements to EQT and $135.2 million to retire long-term intercompany debt to EQT. Prior to the IPO, certain advances from affiliates were viewed as financing transactions as the Partnership would have otherwise obtained demand notes or term loans from EQT Capital Corporation (EQT Capital) to fund these transactions. Subsequent to the IPO, these transactions reflect services rendered on behalf of the Partnership by EQT and its affiliates for operating expenses and are settled monthly. Therefore, these are classified as operating activities subsequent to the IPO.
Capital Requirements
The transmission, storage and gathering businesses can be capital intensive, requiring significant investment to maintain and upgrade existing operations. The below table presents capital expenditures forecasted for 2014 as well as actual amounts expended for 2013, 2012 and 2011.
|
|
|
2014 |
|
2013 |
|
2012 |
|
2011 |
|
|
|
|
(Thousands) |
| ||||||
|
Expansion capital expenditures |
$ |
105,000 |
$ |
50,595 |
$ |
162,574 |
$ |
108,981 |
|
|
Maintenance capital expenditures: |
|
|
|
|
|
|
|
|
|
|
Ongoing maintenance |
|
13,000 |
|
13,192 |
|
13,815 |
|
20,185 |
|
|
Funded regulatory compliance |
|
12,000 |
|
12,093 |
|
6,993 |
|
214 |
|
|
Reimbursable P&A maintenance |
|
— |
|
566 |
|
3,563 |
|
1,738 |
|
|
Reimbursable bare steel maintenance |
|
7,000 |
|
6,574 |
|
6,577 |
|
4,713 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total maintenance capital expenditures |
|
32,000 |
|
32,425 |
|
30,948 |
|
26,850 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures |
$ |
137,000 |
$ |
83,020 |
$ |
193,522 |
$ |
135,831 |
|
|
|
|
|
|
|
|
|
|
|
|
The Partnership does not forecast capital expenditures associated with potential midstream projects not committed as of the filing of this Annual Report on Form 10-K.
Expansion capital expenditures totaled $50.6 million, $162.6 million and $109.0 million for the years ended December 31, 2013, 2012 and 2011, respectively. In 2013, expansion capital expenditures primarily related to the Low Pressure East expansion and the Jefferson compressor station expansion projects. In 2012 and 2011, expansion capital expenditures were primarily related to the Sunrise Pipeline and Blacksville Compressor station projects which were placed into service in the third quarter of 2012.
Maintenance capital expenditures are expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, the Partnership’s operating capacity or operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain throughput, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.
Ongoing maintenance capital expenditures are all maintenance capital expenditures other than funded regulatory compliance and reimbursable maintenance capital expenditures described below. Ongoing maintenance capital expenditures were $13.2 million, $13.8 million and $20.2 million for the years ended December 31, 2013, 2012 and 2011, respectively. In 2011, the Partnership completed a project designed to replace internal piping and measurement and install over pressure protection at one of the Partnership’s main measuring and regulating stations.
Funded regulatory compliance capital expenditures are previously identified maintenance capital expenditures necessary to comply with certain regulatory and other legal requirements. Prior to the IPO, the Partnership identified two specific regulatory compliance initiatives which the Partnership expected to require it to expend approximately $32 million, largely over the two years following the IPO. The Partnership retained approximately $32 million from the net proceeds of the IPO to fund these expenditures. Note that the amounts included as funded regulatory compliance for periods prior to the IPO were included for comparative purposes and were not included in the Partnership’s estimate of $32 million for the initiatives identified prior to the IPO. Funded regulatory compliance capital expenditures were $12.1 million, $7.0 million and $0.2 million for the years ended December 31, 2013, 2012 and 2011, respectively. A full year of expenditures related to the identified initiatives is included in 2013. The specific initiatives of this program are to install remote valve and pressure monitoring equipment on the Partnership’s transmission and storage lines and to relocate certain valve operators above ground and apply corrosion protection. Since the IPO, funded regulatory compliance capital expenditures were $18.9 million.
Under the omnibus agreement, EQT has reimbursement obligations to the Partnership related to certain capital expenditures. For a period of ten years after the closing of the IPO, EQT has agreed to reimburse the Partnership for plugging and abandonment expenditures and other expenditures for certain identified wells of EQT and third parties. The reimbursement obligation of EQT with respect to wells owned by third parties is capped at $1.2 million per year. Additionally, EQT has agreed to reimburse the Partnership for bare steel replacement capital expenditures in the event that ongoing maintenance capital expenditures (other than capital expenditures associated with plugging and abandonment liabilities to be reimbursed by EQT) exceed $17.2 million (with respect to the Partnership’s assets owned at the time of the IPO) in any year. If such ongoing maintenance capital expenditures and bare steel replacement capital expenditures exceed $17.2 million during a year, EQT will reimburse the Partnership for the lesser of (i) the amount of bare steel replacement capital expenditures during such year and (ii) the amount by which such ongoing capital expenditures and bare steel replacement capital expenditures exceeds $17.2 million. This bare steel replacement reimbursement obligation is capped at an aggregate amount of $31.5 million over the ten years following the IPO. The amounts included as reimbursable maintenance for periods prior to the IPO were included for comparative purposes; EQT has no reimbursement obligations for them under the omnibus agreement.
Reimbursable P&A maintenance capital expenditures were $0.6 million, $3.6 million and $1.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. The year over year fluctuations were due to the number of wells being plugged. Reimbursable bare steel maintenance capital expenditures were $6.6 million, $6.6 million and $4.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. The increase in 2013 and 2012 as compared to 2011 is primarily related to the timing of costs associated with this program. In 2013, the Partnership requested reimbursement of $0.6 million for reimbursable P&A maintenance capital expenditures. In 2013, ongoing maintenance capital expenditures totaled $13.2 million and bare steel replacement capital expenditures totaled $6.6 million, for a total of $19.8 million. As a result, the Partnership requested bare steel reimbursements of $2.6 million for 2013. In 2012, the Partnership requested reimbursement of $1.6 million for reimbursable P&A maintenance capital expenditures and $2.7 million for reimbursable bare steel maintenance capital expenditures.
Short-term Borrowings
In February 2014, the Partnership amended its credit facility to increase the borrowing capacity to $750 million. The amended credit facility will expire in February 2019. The credit facility is available to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions and to repurchase units and for general partnership purposes. Subject to certain terms and conditions, the credit facility has an accordion feature that allows the Partnership to increase the available revolving borrowings under the facility by up to an additional $250 million. In addition, the credit facility includes a sublimit up to $75 million for same-day swing line advances and a
sublimit up to $150 million for letters of credit. Further, the Partnership has the ability to request that one or more lenders make term loans to it under the credit facility subject to the satisfaction of certain conditions, which term loans will be secured by cash and qualifying investment grade securities. The Partnership’s obligations under the revolving portion of the credit facility are unsecured. In January 2014, the Partnership borrowed $110 million on its credit facility to make the additional payment to EQT related to the Sunrise Merger. Based on the Partnership’s current consolidated leverage ratio, the Partnership’s maximum borrowing capacity on the credit facility is approximately $600 million.
The Partnership’s credit facility contains various provisions that, if not complied with, could result in termination of the credit facility, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default under the credit facility relate to maintenance of permitted leverage ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. Under the credit facility, the Partnership is required to maintain a consolidated leverage ratio of not more than 5.00 to 1.00 (or, after the Partnership obtains an investment grade rating, not more than 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions).
Distributions
On January 23, 2014, the Partnership announced that the Board of Directors of its general partner declared a cash distribution to the Partnership’s unitholders of $0.46 per unit related to the fourth quarter of 2013. The cash distribution is payable on February 14, 2014 to unitholders of record at the close of business on February 4, 2014. In connection with this cash distribution, EQT received approximately $0.6 million related to its incentive distribution rights.
Schedule of Contractual Obligations
|
|
|
Total |
|
2014 |
|
2015-2016 |
|
2017-2018 |
|
2019+ |
|
|
|
|
(Thousands) |
| ||||||||
|
Capital lease obligation (1) |
$ |
413,512 |
$ |
16,650 |
$ |
33,364 |
$ |
40,691 |
$ |
322,807 |
|
(1) Represents the future projected payments associated with the AVC capital lease obligation (including interest) as of December 31, 2013.
Commitments and Contingencies
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Partnership. While the amounts claimed may be substantial, the Partnership is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Partnership accrues legal and other direct costs related to loss contingencies when actually incurred. The Partnership has established reserves it believes to be appropriate for pending matters, and after consultation with counsel and giving appropriate consideration to available insurance, the Partnership believes that the ultimate outcome of any matter currently pending against the Partnership will not materially affect its business, financial condition, results of operations, liquidity or ability to make distributions.
Off-Balance Sheet Arrangements
The Partnership does not have any off-balance sheet arrangements.
Critical Accounting Policies and Significant Estimates
The Partnership’s significant accounting policies are described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Form 10-K. The discussion and analysis of the Consolidated Financial Statements and results of operations are based upon EQT Midstream Partners’ Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Consolidated Financial Statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities,
revenues and expenses and the related disclosure of contingent assets and liabilities. The following critical accounting policies, which were reviewed by the Partnership’s Audit Committee, relate to the Partnership’s more significant judgments and estimates used in the preparation of its Consolidated Financial Statements. Actual results could differ from those estimates.
Regulatory Accounting: The Partnership’s operations consist of interstate pipeline, intrastate gathering and storage operations subject to regulation by the FERC. Rate regulation provided by the FERC is designed to enable the Partnership to recover the costs of providing the regulated services plus an allowed return on invested capital. The application of ASC Topic 980 “Regulated Operations” allows the Partnership to defer expenses and income on its consolidated balance sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the statements of consolidated operations for a non-regulated company. The deferred regulatory assets and liabilities are then recognized in the statements of consolidated operations in the period in which the same amounts are reflected in rates. The amounts deferred in the consolidated balance sheets relate primarily to the accounting for income taxes, post-retirement benefit costs and base storage gas. The amounts established for accounting for income taxes were generated during the pre-IPO period when the Partnership was included as part of EQT’s consolidated federal tax return. The Partnership believes that it will continue to be subject to rate regulation that will provide for the recovery of deferred costs.
The Partnership believes that the accounting estimates related to regulatory accounting are “critical accounting policies” because the underlying assumptions regarding the recovery of deferred costs and revenues in future rates can change from period to period and changes in the recoverability of these amounts could potentially have a material impact on the results of operations and on working capital. Actual rate recovery amounts and periods may vary significantly from management’s estimates and may impact the realization or recovery of regulatory assets and liabilities.
Property, Plant and Equipment: Property, plant and equipment are stated at amortized cost. Maintenance projects that do not increase the overall life of the related assets are expensed as incurred. Expenditures that extend the useful life of the underlying asset are capitalized.
Depreciation is recorded using composite rates on a straight-line basis. The overall rate of depreciation for the years ended December 31, 2013, 2012 and 2011 were approximately 2.1%, 2.0% and 1.9%, respectively. The Partnership estimates its pipelines have useful lives ranging from 37 years to 65 years and its compression equipment has useful lives of 45 years. Depreciation rates are re-evaluated each time the Partnership files with the FERC for a change in its transportation and storage rates.
Whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, the Partnership reviews the long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets’ undiscounted cash flows, the Partnership estimates an impairment loss by taking the difference between the carrying value and fair value of the assets.
The Partnership believes that the accounting estimate related to asset impairment is a “critical accounting estimate” as it is susceptible to change from period to period because it requires management to make assumptions about cash flows over future years. These assumptions affect the amount of an impairment, which would have an impact on the results of operations and financial position. Management’s assumptions about future cash flows require significant judgment because actual operating levels have fluctuated in the past and are expected to do so in the future.
Contingencies and Asset Retirement Obligations: The Partnership is involved in various regulatory and legal proceedings that arise in the ordinary course of business. A liability is recorded for contingencies based upon the Partnership’s assessment that a loss is probable and that the amount of the loss can be reasonably estimated. The Partnership considers many factors in making these assessments, including history and specifics of each matter. Estimates are developed in consultation with legal counsel and are based upon an analysis of potential results.
The Partnership operates and maintains its transmission and storage system and its gathering system and intends to do so as long as supply and demand for natural gas exists, which is expected for the foreseeable future. Therefore, the Partnership believes that it cannot reasonably estimate the asset retirement obligations for its system assets as these assets have indeterminate lives.
The Partnership believes that the accounting estimates related to contingencies and asset retirement obligations are “critical accounting estimates” because it must assess the probability of loss related to contingencies and the expected amount and timing of asset retirement obligations. In addition, the Partnership must determine the estimated present value of future liabilities. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the assumptions.
Equity-Based Compensation: The Partnership has awarded equity-based compensation in connection with the Partnership compensation plans and programs. The program awards will be paid in units, and as such the Partnership treats these awarded units as equity awards. Awards that have a fixed estimate due to a market condition require the Partnership to obtain a valuation. Significant assumptions made in valuing the Partnership’s awards include the market price of units at payout date, total unitholder return threshold to be achieved, volatility, risk-free rate, term, dividend yield and forfeiture rate.
The Partnership believes that the accounting estimates related to equity-based compensation are “critical accounting estimates” because of the assumptions affecting the ultimate payout of the awards and the market price and volatility of the Partnership’s common units. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Partnership’s assumptions.
Revenue Recognition: Revenues relating to the transmission, storage and gathering of natural gas are recognized in the period service is provided. Reservation revenues on firm contracted capacity are recognized over the contract period based on the contracted volume regardless of the amount of natural gas that is transported. Revenues associated with transported volumes under firm and interruptible services are recognized as physical deliveries of natural gas are made. Revenue is recognized for gathering activities when deliveries of natural gas are made.
The Partnership encounters risks associated with the collection of its accounts receivable. As such, the Partnership records a monthly provision for accounts receivable that are considered to be uncollectible. In order to calculate the appropriate monthly provision, a historical rate of accounts receivable losses as a percentage of total revenue is utilized. This historical rate is applied to the current revenues on a monthly basis and is updated periodically based on events that may change the rate, such as a significant change to the natural gas industry or to the economy as a whole. Management reviews the adequacy of the allowance on a quarterly basis using the assumptions that apply at that time.
The Partnership believes that the accounting estimates related to revenue recognition and the allowance for doubtful accounts receivable are “critical accounting policies” because the underlying assumptions used for the allowance can change from period to period and the changes in the allowance could potentially have a material impact on the results of operations and on working capital. In addition, the actual mix of customers and their ability to pay may vary significantly from management’s estimates and may impact the collectability of customer accounts.
Emerging Growth Company: The JOBS Act provides that an emerging growth company may delay adopting new or revised accounting standards until such time as those standards apply to private companies. The Partnership has irrevocably elected to opt out of this exemption and, therefore, will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Other than the base gas the Partnership purchases and uses in its natural gas storage facilities, which is necessary to maintain pressure and deliverability in its storage pools, and the small amount of natural gas it purchases for system operations, the Partnership generally does not take title to the natural gas that is stored or transported on its transmission system; accordingly, the Partnership is not exposed to commodity price fluctuations
on natural gas stored in its facilities or transported through its pipelines by its customers. Base gas purchased and used in natural gas storage facilities, which was generally purchased more than 30 years ago, is considered a long-term asset and is not re-valued at current market prices. Under the Partnership’s contractual arrangements with its customers, the Partnership is entitled to retain a specified volume of natural gas in order to compensate the Partnership for its fuel usage and other requirements. Historically, the natural gas volumes retained from the Partnership’s transmission and storage customers as retention pursuant to the Partnership’s transmission and storage agreements have been sufficient to cover the Partnership’s fuel usage and other requirements on the transmission and storage system. However, fuel usage and other requirements on the gathering system have historically exceeded the natural gas volumes retained from the Partnership’s gathering customers pursuant to its gathering agreements. As a consequence, the Partnership has purchased natural gas to make up for the difference. For the years ended December 31, 2013, 2012 and 2011, the Partnership’s actual commodity usage volumes exceeded the amounts recovered from its gathering customers for which the Partnership recognized $3.3 million, $4.0 million and $4.9 million, respectively, of purchased gas cost as a component of operating and maintenance expense. Except for the base gas in its natural gas storage facilities which the Partnership considers to be a long-term asset and volume and pricing variations related to the volumes of fuel purchased to make up for fuel usage and other requirements in excess of amounts recovered from customers, the Partnership’s current business model is designed to minimize its exposure to fluctuations in commodity prices. As a result, absent other market factors that could adversely impact its operations, changes in the price of natural gas over the intermediate term should not materially impact the Partnership’s operations. The Partnership has not historically engaged in material commodity hedging activities relating to its assets. However, the Partnership may engage in commodity hedging activities in the future, particularly if it undertakes growth projects or engages in acquisitions that expose it to direct commodity price risk.
Interest Rate Risk
The Partnership maintains a credit facility. The Partnership may from time to time hedge the interest on portions of its borrowings under the credit facility in order to manage risks associated with floating interest rates.
Credit Risk
The Partnership is exposed to credit risk. Credit risk represents the loss that it would incur if a counterparty fails to perform under its contractual obligations. Approximately 59% and 87% of the Partnership’s third party accounts receivable balances of $8.5 million and $3.7 million as of December 31, 2013 and 2012, respectively, represent amounts due from marketers. The Partnership manages its exposure to credit risk associated with customers through credit analysis, credit approval, credit limits and monitoring procedures. For certain transactions, the Partnership may request letters of credit, cash collateral, prepayments or guarantees as forms of credit support. The Partnership’s tariff requires customers that do not meet specified credit standards to provide three months of credit support; however, the Partnership is exposed to credit risk beyond this three month period when its tariff does not require its customers to provide additional credit support. For some of the Partnership’s more recent long-term contracts associated with system expansions, it has entered into negotiated credit agreements that provide for enhanced forms of credit support if certain credit standards are not met. The Partnership has historically experienced only minimal credit losses in connection with its receivables. The Partnership is also exposed to the credit risk of EQT, its largest customer. In connection with the IPO, EQT guaranteed all payment obligations, up to a maximum of $50 million, due and payable to Equitrans by EQT Energy, one of Equitrans’ largest customers. The EQT guaranty will terminate on November 30, 2023 unless terminated earlier by EQT upon 10 days written notice. At December 31, 2013, EQT’s public senior debt had an investment grade credit rating.
Item 8. Financial Statements and Supplementary Data
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Page Reference |
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67 | |
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68 | |
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69 | |
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Consolidated Balance Sheets as of December 31, 2013 and 2012 |
70 |
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71 | |
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72 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of EQT Midstream Services, LLC and Unitholders of
EQT Midstream Partners, LP
We have audited the accompanying consolidated balance sheets of EQT Midstream Partners, LP (including its Predecessor as defined in Note 1 and collectively, the Partnership) as of December 31, 2013 and 2012, and the related statements of consolidated operations, 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. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of EQT Midstream Partners, LP at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.
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Pittsburgh, Pennsylvania |
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February 20, 2014 |
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EQT MIDSTREAM PARTNERS, LP
STATEMENTS OF CONSOLIDATED OPERATIONS
YEARS ENDED DECEMBER 31,
|
|
|
2013 (a) |
|
2012 (a) |
|
2011 | |||||
|
|
|
(Thousands, except per unit amounts) |
| ||||||||
|
Operating revenues: |
|
|
|
|
|
|
|
|
| ||
|
Operating revenues – affiliate |
$ |
142,437 |
|
$ |
106,180 |
|
$ |
86,556 |
| ||
|
Operating revenues – third party |
|
43,454 |
|
|
30,730 |
|
|
23,057 |
| ||
|
Total operating revenues |
|
185,891 |
|
|
136,910 |
|
|
109,613 |
| ||
|
|
|
|
|
|
|
|
|
|
| ||
|
Operating expenses: |
|
|
|
|
|
|
|
|
| ||
|
Operating and maintenance |
|
28,954 |
|
|
29,405 |
|
|
26,221 |
| ||
|
Selling, general and administrative |
|
21,497 |
|
|
16,614 |
|
|
17,302 |
| ||
|
Depreciation and amortization |
|
21,190 |
|
|
15,740 |
|
|
11,470 |
| ||
|
Total operating expenses |
|
71,641 |
|
|
61,759 |
|
|
54,993 |
| ||
|
|
|
|
|
|
|
|
|
|
| ||
|
Operating income |
|
114,250 |
|
|
75,151 |
|
|
54,620 |
| ||
|
|
|
|
|
|
|
|
|
|
| ||
|
Other income, net |
|
1,242 |
|
|
8,228 |
|
|
3,826 |
| ||
|
Interest expense, net |
|
1,672 |
|
|
2,944 |
|
|
5,050 |
| ||
|
Income before income taxes |
|
113,820 |
|
|
80,435 |
|
|
53,396 |
| ||
|
Income tax expense |
|
4,053 |
|
|
17,313 |
|
|
20,807 |
| ||
|
Net income |
$ |
109,767 |
|
$ |
63,122 |
|
$ |
32,589 |
| ||
|
|
|
|
|
|
|
|
|
|
| ||
|
Calculation of limited partner interest in net income: |
|
|
|
|
|
|
|
|
| ||
|
Net income |
$ |
109,767 |
|
$ |
63,122 |
|
|
N/A |
| ||
|
Less pre-acquisition income allocated to parent |
|
(6,189 |
) |
|
(26,563 |
) |
|
N/A |
| ||
|
Less general partner interest in net income |
|
(2,927 |
) |
|
(791 |
) |
|
N/A |
| ||
|
Limited partner interest in net income |
$ |
100,651 |
|
$ |
35,768 |
|
|
N/A |
| ||
|
|
|
|
|
|
|
|
|
|
| ||
|
Net income per limited partner unit – basic |
$ |
2.47 |
|
$ |
1.03 |
|
|
N/A |
| ||
|
Net income per limited partner unit – diluted |
$ |
2.46 |
|
$ |
1.03 |
|
|
N/A |
| ||
|
|
|
|
|
|
|
|
|
|
| ||
|
Weighted average limited partner units outstanding – basic |
|
40,739 |
|
|
34,679 |
|
|
N/A |
| ||
|
Weighted average limited partner units outstanding – diluted |
|
40,847 |
|
|
34,734 |
|
|
N/A |
| ||
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
| |||||||||
|
(a) |
|
Financial statements for 2012 and the first six months of 2013 have been retrospectively recast to reflect the inclusion of Sunrise Pipeline, LLC (Sunrise), which merged into Equitrans, L.P., a subsidiary of EQT Midstream Partners, LP, on July 22, 2013 (Sunrise Merger). See Note 2 for further discussion. | |||||||||
See notes to consolidated financial statements.
EQT MIDSTREAM PARTNERS, LP
STATEMENTS OF CONSOLIDATED CASH FLOWS
YEARS ENDED DECEMBER 31,
|
|
|
2013 (a) |
|
2012 (a) |
|
2011 | |||||
|
|
|
(Thousands) |
| ||||||||
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
| ||
|
Net income |
$ |
109,767 |
|
$ |
63,122 |
|
$ |
32,589 |
| ||
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
| ||
|
Depreciation and amortization |
|
21,190 |
|
|
15,740 |
|
|
11,470 |
| ||
|
Deferred income taxes |
|
(262 |
) |
|
49,205 |
|
|
12,506 |
| ||
|
Other income |
|
(1,242 |
) |
|
(8,228 |
) |
|
(3,826 |
) | ||
|
Non-cash long term compensation expense |
|
981 |
|
|
2,282 |
|
|
2,249 |
| ||
|
Non-cash adjustments |
|
(680 |
) |
|
(2,508 |
) |
|
— |
| ||
|
Changes in other assets and liabilities: |
|
|
|
|
|
|
|
|
| ||
|
Accounts receivable |
|
(4,720 |
) |
|
(10,825 |
) |
|
(492 |
) | ||
|
Accounts payable |
|
(17,765 |
) |
|
4,571 |
|
|
14,470 |
| ||
|
Regulatory assets, net |
|
2,407 |
|
|
1,448 |
|
|
(1,743 |
) | ||
|
Due (to)/from EQT affiliates |
|
9,744 |
|
|
21,045 |
|
|
(16,846 |
) | ||
|
Other assets and other liabilities |
|
1,915 |
|
|
(7,253 |
) |
|
(2,813 |
) | ||
|
Net cash provided by operating activities |
|
121,335 |
|
|
128,599 |
|
|
47,564 |
| ||
|
|
|
|
|
|
|
|
|
|
| ||
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
| ||
|
Capital expenditures |
|
(83,020 |
) |
|
(193,522 |
) |
|
(135,831 |
) | ||
|
Net cash used in investing activities |
|
(83,020 |
) |
|
(193,522 |
) |
|
(135,831 |
) | ||
|
|
|
|
|
|
|
|
|
|
| ||
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
| ||
|
Proceeds from the issuance of common units, net of offering costs |
|
529,442 |
|
|
276,780 |
|
|
— |
| ||
|
Sunrise Merger payment |
|
(507,500 |
) |
|
— |
|
|
— |
| ||
|
Distribution of proceeds from the issuance of common units |
|
— |
|
|
(230,887 |
) |
|
— |
| ||
|
Due to/from EQT |
|
— |
|
|
(49,657 |
) |
|
58,405 |
| ||
|
Retirements of long-term debt |
|
— |
|
|
(135,235 |
) |
|
— |
| ||
|
Partners’ investments |
|
— |
|
|
276,543 |
|
|
27,250 |
| ||
|
Capital contributions |
|
5,631 |
|
|
1,863 |
|
|
— |
| ||
|
Distributions paid to unitholders |
|
(66,176 |
) |
|
(12,386 |
) |
|
— |
| ||
|
Pre-merger and predecessor distributions paid to EQT |
|
(31,390 |
) |
|
(10,193 |
) |
|
(11,729 |
) | ||
|
Payment of credit facility fees |
|
— |
|
|
(1,864 |
) |
|
— |
| ||
|
Net cash (used in) provided by financing activities |
|
(69,993 |
) |
|
114,964 |
|
|
73,926 |
| ||
|
|
|
|
|
|
|
|
|
|
| ||
|
Net change in cash and cash equivalents |
|
(31,678 |
) |
|
50,041 |
|
|
(14,341 |
) | ||
|
Cash and cash equivalents at beginning of year |
|
50,041 |
|
|
— |
|
|
14,341 |
| ||
|
Cash and cash equivalents at end of year |
$ |
18,363 |
|
$ |
50,041 |
|
$ |
— |
| ||
|
|
|
|
|
|
|
|
|
|
| ||
|
Cash paid during the year for: |
|
|
|
|
|
|
|
|
| ||
|
Interest paid |
$ |
939 |
|
$ |
6,461 |
|
$ |
5,663 |
| ||
|
|
|
|
|
|
|
|
|
|
| ||
|
Non-cash activity during the year: |
|
|
|
|
|
|
|
|
| ||
|
Non-cash distributions |
$ |
— |
|
$ |
12,229 |
|
$ |
— |
| ||
|
Elimination of net current and deferred tax liabilities |
$ |
43,083 |
|
$ |
143,587 |
|
$ |
— |
| ||
|
Common and GP units issued for Sunrise Merger |
$ |
32,500 |
|
$ |
— |
|
$ |
— |
| ||
|
Contingent consideration |
$ |
110,000 |
|
$ |
— |
|
$ |
— |
| ||
|
Capital lease asset/obligation |
$ |
134,395 |
|
$ |
— |
|
$ |
— |
| ||
|
|
|
|
|
|
|
|
|
|
| ||
|
(a) |
|
Financial statements for 2012 and the first six months of 2013 have been retrospectively recast to reflect the Sunrise Merger. See Note 2 for further discussion. | |||||||||
See notes to consolidated financial statements.
EQT MIDSTREAM PARTNERS, LP
YEARS ENDED DECEMBER 31,
|
|
|
2013 |
|
2012 (a) |
| ||
|
|
|
(Thousands, except number of |
| ||||
|
ASSETS |
|
|
|
|
| ||
|
Current assets: |
|
|
|
|
| ||
|
Cash and cash equivalents |
$ |
18,363 |
$ |
50,041 |
| ||
|
Accounts receivable (net of allowance for doubtful accounts of $152 and $64 as of December 31, 2013 and 2012, respectively) |
|
8,463 |
|
3,743 |
| ||
|
Accounts receivable – affiliate |
|
12,758 |
|
11,911 |
| ||
|
Due from related party |
|
6,454 |
|
10,133 |
| ||
|
Other current assets |
|
537 |
|
645 |
| ||
|
Total current assets |
|
46,575 |
|
76,473 |
| ||
|
|
|
|
|
|
| ||
|
Property, plant and equipment |
|
1,007,299 |
|
800,844 |
| ||
|
Less: accumulated depreciation |
|
(158,411) |
|
(143,713) |
| ||
|
Net property, plant and equipment |
|
848,888 |
|
657,131 |
| ||
|
|
|
|
|
|
| ||
|
Regulatory assets |
|
16,246 |
|
18,223 |
| ||
|
Other assets |
|
1,304 |
|
1,810 |
| ||
|
Total assets |
$ |
913,013 |
$ |
753,637 |
| ||
|
|
|
|
|
|
| ||
|
LIABILITIES AND PARTNERS’ CAPITAL |
|
|
|
|
| ||
|
Current liabilities: |
|
|
|
|
| ||
|
Accounts payable |
$ |
7,328 |
$ |
25,093 |
| ||
|
Due to related party |
|
110,000 |
|
1,273 |
| ||
|
Lease obligation - current |
|
662 |
|
— |
| ||
|
Accrued liabilities |
|
11,088 |
|
8,900 |
| ||
|
Total current liabilities |
|
129,078 |
|
35,266 |
| ||
|
|
|
|
|
|
| ||
|
Deferred income taxes, net |
|
— |
|
40,842 |
| ||
|
Lease obligation |
|
133,733 |
|
— |
| ||
|
Other long-term liabilities |
|
6,014 |
|
4,680 |
| ||
|
Total liabilities |
|
268,825 |
|
80,788 |
| ||
|
|
|
|
|
|
| ||
|
Partners’ capital: |
|
|
|
|
| ||
|
Predecessor equity |
|
— |
|
197,773 |
| ||
|
Common units (30,468,902 and 17,339,718 units issued and outstanding at December 31, 2013 and 2012, respectively) |
|
818,431 |
|
313,304 |
| ||
|
Subordinated units (17,339,718 units issued and outstanding at December 31, 2013 and 2012) |
|
(175,996) |
|
153,664 |
| ||
|
General partner interest (975,686 and 707,744 units issued and outstanding at December 31, 2013 and 2012, respectively) |
|
1,753 |
|
8,108 |
| ||
|
Total partners’ capital |
|
644,188 |
|
672,849 |
| ||
|
Total liabilities and partners’ capital |
$ |
913,013 |
$ |
753,637 |
| ||
|
|
|
| |||||
|
|
|
| |||||
|
(a) |
Financial statements for 2012 have been retrospectively recast to reflect the Sunrise Merger. See Note 2 for further discussion. | ||||||
See notes to consolidated financial statements.
EQT MIDSTREAM PARTNERS, LP
STATEMENTS OF CONSOLIDATED PARTNERS’ CAPITAL
YEARS ENDED DECEMBER 31, 2013, 2012 and 2011 (a)
|
|
|
|
|
Partners’ Capital |
|
|
| |||||
|
|
|
Predecessor |
|
Limited Partners |
|
General |
|
|
| |||
|
|
|
Equity |
|
Common |
|
Subordinated |
|
Partner |
|
Total |
| |
|
|
|
(Thousands) |
| |||||||||
|
Balance at January 1, 2011 |
$ |
125,523 |
$ |
— |
$ |
— |
$ |
— |
$ |
125,523 |
| |
|
Investment by partners |
|
27,350 |
|
— |
|
— |
|
— |
|
27,350 |
| |
|
Distributions paid |
|
(11,729) |
|
— |
|
— |
|
— |
|
(11,729) |
| |
|
Net income |
|
32,589 |
|
— |
|
— |
|
— |
|
32,589 |
| |
|
Balance at December 31, 2011 |
$ |
173,733 |
$ |
— |
$ |
— |
$ |
— |
$ |
173,733 |
| |
|
Net income |
|
26,563 |
|
16,345 |
|
19,423 |
|
791 |
|
63,122 |
| |
|
Investment by partners |
|
276,543 |
|
— |
|
— |
|
— |
|
276,543 |
| |
|
Distributions paid |
|
(10,193) |
|
— |
|
— |
|
— |
|
(10,193) |
| |
|
Non-cash distributions |
|
(12,229) |
|
— |
|
— |
|
— |
|
(12,229) |
| |
|
Elimination of net current and deferred tax liabilities |
|
143,587 |
|
— |
|
— |
|
— |
|
143,587 |
| |
|
Contribution of net assets to EQT Midstream Partners, LP |
|
(400,231) |
|
56,470 |
|
330,279 |
|
13,482 |
|
— |
| |
|
Issuance of common units to public, net of offering costs |
|
— |
|
276,780 |
|
— |
|
— |
|
276,780 |
| |
|
Distribution of proceeds |
|
— |
|
(32,837) |
|
(192,049) |
|
(6,001) |
|
(230,887) |
| |
|
Capital contribution |
|
— |
|
2,080 |
|
2,080 |
|
84 |
|
4,244 |
| |
|
Equity-based compensation plans |
|
— |
|
535 |
|
— |
|
— |
|
535 |
| |
|
Distributions to unitholders |
|
— |
|
(6,069) |
|
(6,069) |
|
(248) |
|
(12,386) |
| |
|
Balance at December 31, 2012 |
$ |
197,773 |
$ |
313,304 |
$ |
153,664 |
$ |
8,108 |
$ |
672,849 |
| |
|
Net income |
|
6,189 |
|
58,673 |
|
41,978 |
|
2,927 |
|
109,767 |
| |
|
Capital contribution |
|
— |
|
1,705 |
|
1,363 |
|
64 |
|
3,132 |
| |
|
Equity-based compensation plans |
|
— |
|
981 |
|
— |
|
— |
|
981 |
| |
|
Distributions to unitholders |
|
— |
|
(37,774) |
|
(26,877) |
|
(1,525) |
|
(66,176) |
| |
|
Pre-merger distributions to EQT |
|
(31,390) |
|
— |
|
— |
|
— |
|
(31,390) |
| |
|
Proceeds from equity offering, net of offering costs |
|
— |
|
529,442 |
|
— |
|
— |
|
529,442 |
| |
|
Elimination of net current and deferred tax liabilities |
|
43,083 |
|
— |
|
— |
|
— |
|
43,083 |
| |
|
Sunrise net assets from EQT |
|
(215,655) |
|
— |
|
— |
|
— |
|
(215,655) |
| |
|
Issuance of units |
|
— |
|
20,845 |
|
— |
|
11,655 |
|
32,500 |
| |
|
Purchase price in excess of net assets from EQT |
|
— |
|
(68,745) |
|
(346,124) |
|
(19,476) |
|
(434,345) |
| |
|
Balance at December 31, 2013 |
$ |
— |
$ |
818,431 |
$ |
(175,996) |
$ |
1,753 |
$ |
644,188 |
| |
|
|
| |||||||||||
|
(a) |
Financial statements for 2011, 2012 and the first six months of 2013 have been retrospectively recast to reflect the Sunrise Merger. See Note 2 for further discussion. | |||||||||||
See notes to consolidated financial statements.
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
1. Summary of Operations and Significant Accounting Policies
Organization
EQT Midstream Partners, LP (EQT Midstream Partners or the Partnership), which closed its initial public offering (IPO) on July 2, 2012, is a growth-oriented Delaware limited partnership formed by EQT Corporation in January 2012. Equitrans, L.P. (Equitrans) is a Pennsylvania limited partnership and the predecessor for accounting purposes (the Predecessor) of EQT Midstream Partners. EQT Midstream Services, LLC is the Partnership’s general partner. References in these consolidated financial statements to the Partnership, when used for periods prior to the IPO, refer to Equitrans. References in these consolidated financial statements to the Partnership, when used for periods beginning at or following the IPO, refer collectively to the Partnership and its consolidated subsidiaries. References in these consolidated financial statements to EQT refer collectively to EQT Corporation and its consolidated subsidiaries. Immediately prior to the closing of the IPO, EQT Corporation contributed all of the partnership interests in Equitrans to the Partnership. Therefore, the historical financial statements contained in this report reflect the assets, liabilities and results of operations of Equitrans presented on a carve-out basis, excluding the financial position and results of operations of the Big Sandy Pipeline (as described in the following section) for periods ending before July 2, 2012 and EQT Midstream Partners for periods beginning at or following July 2, 2012. Additionally, as discussed in Note 2, the Partnership’s consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of Sunrise, which was merged into the Partnership on July 22, 2013, because the transaction was a transfer between entities under common control.
The Partnership does not have any employees. Operational support for the Partnership is provided by EQT Gathering, LLC (EQT Gathering), one of EQT’s operating subsidiaries engaged in certain midstream business operations. EQT Gathering’s employees manage and conduct the Partnership’s daily business operations.
Prior to July 2011, Equitrans owned an approximately 70 mile Federal Energy Regulatory Commission (FERC)-regulated transmission pipeline located in eastern Kentucky (Big Sandy Pipeline). Construction on the Big Sandy Pipeline began in 2006 and was completed in 2008. Equitrans operated the pipeline until April 2011, when it was transferred to an affiliate. Such affiliate was subsequently sold in July 2011 to an unrelated third party pipeline operator. Equitrans has no continuing operations in Kentucky or retained interest in the Big Sandy Pipeline.
Immediately prior to the closing of the IPO, EQT contributed all of the partnership interests in Equitrans to the Partnership and Equitrans distributed its accounts receivable to EQT via a non-cash distribution of approximately $12 million. The Partnership issued 14,375,000 common units in the IPO. The Partnership received net proceeds of approximately $277 million, after deducting the underwriters’ discount and offering expenses. Approximately $231 million of the proceeds were distributed to EQT, $12 million was retained by the Partnership to replenish amounts distributed by Equitrans to EQT prior to the IPO, $32 million was retained by the Partnership to pre-fund certain maintenance capital expenditures and $2 million was used by the Partnership to pay credit facility origination fees associated with its credit agreement described in Note 7. In connection with the IPO, Equitrans’ net current and deferred taxes of approximately $144 million were eliminated. See further discussion in Note 5.
In July 2013, the Partnership completed an underwritten public offering of an additional 12,650,000 common units. The Partnership received net proceeds of approximately $529 million from this offering after deducting the underwriters’ discount and offering expenses of approximately $21 million. Net proceeds from the offering were used to fund the cash consideration paid to EQT in connection with the Sunrise Merger discussed in Note 2.
Limited Partner and General Partner Units
The following table summarizes common, subordinated and general partner units issued from the date of the Partnership’s IPO through December 31, 2013.
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
|
|
|
Limited Partner Units |
|
General |
|
|
| ||
|
|
|
Common |
|
Subordinated |
|
Partner Units |
|
Total |
|
|
Issued in connection with IPO |
|
17,339,718 |
|
17,339,718 |
|
707,744 |
|
35,387,180 |
|
|
Balance at December 31, 2012 |
|
17,339,718 |
|
17,339,718 |
|
707,744 |
|
35,387,180 |
|
|
July 2013 equity offering |
|
12,650,000 |
|
— |
|
— |
|
12,650,000 |
|
|
Sunrise Merger consideration |
|
479,184 |
|
— |
|
267,942 |
|
747,126 |
|
|
Balance at December 31, 2013 |
|
30,468,902 |
|
17,339,718 |
|
975,686 |
|
48,784,306 |
|
As of December 31, 2013, EQT retained a 44.6% equity interest in the Partnership, which includes 3,443,902 common units, 17,339,718 subordinated units and 975,686 general partner units. EQT also holds the incentive distribution rights.
Nature of Business
The Partnership is a growth-oriented limited partnership formed by EQT to own, operate, acquire and develop midstream assets in the Appalachian Basin. The Partnership provides midstream services to EQT and third parties in the Appalachian Basin across 21 counties in Pennsylvania and West Virginia through two primary assets: the transmission and storage system and the gathering system.
Transmission and Storage System: The Partnership’s transmission and storage system includes an approximately 700 mile FERC-regulated interstate pipeline that connects to five interstate pipelines and multiple distribution companies. The transmission system is supported by 14 associated natural gas storage reservoirs with approximately 400 MMcf per day of peak withdrawal capability and 32 Bcf of working gas capacity and 24 compressor units. As of December 31, 2013, the transmission assets had total throughput capacity of approximately 2.25 TBtu per day. The Partnership also operates the Allegheny Valley Connector (AVC) facilities as described in Note 11. Revenues are primarily driven by the Partnership’s firm transmission and storage contracts.
Gathering System: The Partnership’s gathering system consists of approximately 1,600 miles of FERC-regulated low-pressure gathering lines. Substantially all of the revenues associated with the Partnership’s gathering system are generated under interruptible gathering service contracts.
Significant Accounting Policies
Principles of Consolidation: The Consolidated Financial Statements include the accounts of EQT Midstream Partners, LP and all subsidiaries and partnerships. Transactions between the Partnership and EQT have been identified in the Consolidated Financial Statements as transactions between related parties in Note 4.
Segments: Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and are subject to evaluation by the Partnership’s chief operating decision maker in deciding how to allocate resources.
The Partnership reports its operations in two segments, which reflect its lines of business. Transmission and storage includes the Partnership’s FERC-regulated interstate pipeline and storage business. Gathering includes the FERC-regulated low pressure gathering system. The operating segments are evaluated on their contribution to the Partnership’s operating income.
All of the Partnership’s operating revenues, income from continuing operations and assets are generated or located in the United States.
Reclassification: Certain previously reported amounts have been reclassified to conform to the current year presentation.
Use of Estimates: The preparation of financial statements in conformity with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and accompanying notes. Actual results could differ from those estimates.
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
Cash and Cash Equivalents: The Partnership considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. Interest earned on cash equivalents is included as a reduction to interest expense, net in the accompanying statements of consolidated operations.
Fair Value of Financial Instruments: The carrying value of cash and cash equivalents, accounts receivable, amounts due to/from related parties and accounts payable approximates fair value due to the short maturity of the instruments.
Trade and Other Receivables: Trade and other receivables are stated at their historical carrying amount. Judgment is required to assess the ultimate realization of accounts receivable, including assessing the probability of collection and the creditworthiness of customers. Based upon management’s assessments, allowances for doubtful accounts of approximately $0.2 million and $0.1 million were provided at December 31, 2013 and 2012, respectively. The Partnership also has receivables due from EQT as discussed in Note 4.
Property, Plant and Equipment: The Partnership’s property, plant and equipment are stated at depreciated cost. Maintenance projects that do not increase the overall life of the related assets are expensed as incurred. Expenditures that extend the useful life of the underlying asset are capitalized.
|
|
|
As of December 31, |
| ||||
|
|
|
2013 |
|
|
|
2012 |
|
|
|
|
(Thousands) |
| ||||
|
Transmission and storage assets |
$ |
904,699 |
|
|
$ |
697,244 |
|
|
Accumulated depreciation |
|
(135,949 |
) |
|
|
(120,630 |
) |
|
Net transmission and storage assets |
|
768,750 |
|
|
|
576,614 |
|
|
Gathering assets |
|
102,600 |
|
|
|
103,600 |
|
|
Accumulated depreciation |
|
(22,462 |
) |
|
|
(23,083 |
) |
|
Net gathering assets |
|
80,138 |
|
|
|
80,517 |
|
|
Net property, plant and equipment |
$ |
848,888 |
|
|
$ |
657,131 |
|
Depreciation is recorded using composite rates on a straight-line basis. The overall rate of depreciation for the years ended December 31, 2013, 2012 and 2011 were approximately 2.1%, 2.0% and 1.9%, respectively. The Partnership estimates the pipelines have useful lives ranging from 37 years to 65 years and the compression equipment has a useful life of 45 years. Depreciation rates are re-evaluated each time the Partnership files with the FERC for a change in the Partnership’s transportation and storage rates.
Whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, the Partnership reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. The transmission, storage and gathering systems are evaluated as one asset group for impairment purposes because the cash flows are not independent of one another. If the carrying value exceeds the sum of the assets’ undiscounted cash flows, the Partnership estimates an impairment loss equal to the difference between the carrying value and fair value of the assets.
Natural Gas Imbalances: The Partnership experiences natural gas imbalances when the actual amount of natural gas delivered from a pipeline system or storage facility differs from the amount of natural gas scheduled to be delivered. The Partnership values these imbalances due to or from shippers and operators at current index prices. Imbalances are settled in-kind, subject to the terms of the FERC tariff.
Imbalances as of December 31, 2013 and 2012 were $1.1 million and $1.8 million, respectively, and are included in accrued liabilities in the accompanying consolidated balance sheets with offsetting amounts recorded to system gas, a component of property, plant and equipment. The Partnership classifies the imbalance liabilities as current as it expects to settle them within a year.
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
Accrued Liabilities: Included in accrued liabilities in the Partnership’s consolidated balance sheets is approximately $7 million and $5 million of incentive compensation at December 31, 2013 and 2012, respectively.
Regulatory Accounting: The Partnership’s operations consist of interstate pipeline, intrastate gathering and storage operations subject to regulation by the FERC. Rate regulation provided by the FERC is designed to enable the Partnership to recover the costs of providing the regulated services plus an allowed return on invested capital. The application of regulatory accounting allows the Partnership to defer expenses and income in its consolidated balance sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the statements of consolidated operations for a non-regulated entity. The deferred regulatory assets and liabilities are then recognized in the statements of consolidated operations in the period in which the same amounts are reflected in rates. The amounts deferred in the consolidated balance sheets relate primarily to the accounting for income taxes, post-retirement benefit costs and base storage gas. The amounts established for accounting for income taxes were primarily generated during the pre-IPO period when the Partnership was included as part of EQT’s consolidated federal tax return. The Partnership believes that it will continue to be subject to rate regulation that will provide for the recovery of deferred costs.
On April 5, 2006, the FERC approved a settlement to Equitrans’ consolidated 2005 and 2004 rate case filings. The settlement became effective on June 1, 2006. This settlement (i) increased the Partnership’s base tariff rates, (ii) implemented an annual surcharge for the tracking and recovery of certain pipeline safety costs among other programs and (iii) implemented a mechanism for recovering migrated base gas. On March 22, 2013, the FERC approved a Stipulation and Agreement of Settlement (the Settlement) that eliminated the tracking of pipeline safety costs by replacing the pipeline safety cost surcharge with a pipeline safety cost rate. Additionally, the Settlement eliminated the base storage gas recovery limit established in the 2006 rate case settlement.
Revenue Recognition: Revenues relating to the transmission, storage and gathering of natural gas are recognized in the period service is provided. Reservation revenues on firm contracted capacity are recognized ratably over the contract period based on the contracted volume regardless of the amount of natural gas that is transported. Revenues associated with transported volumes under firm and interruptible services are recognized as physical deliveries of natural gas are made. Revenue is recognized for gathering activities when deliveries of natural gas are made.
Allowance for Funds Used During Construction (AFUDC): The Partnership capitalizes the carrying costs for the construction of certain regulated long-term assets and amortizes the costs over the life of the related assets. The calculated AFUDC includes capitalization of the cost of financing construction of assets subject to regulation by the FERC. A computed interest cost and a designated cost of equity for financing the construction of these regulated assets are recorded in the consolidated financial statements. AFUDC applicable to equity funds recorded in other income in the statements of consolidated operations for the years ended December 31, 2013, 2012 and 2011 was $1.2 million, $6.7 million and $3.8 million, respectively. AFUDC applicable to interest cost for the years ended December 31, 2013, 2012 and 2011 was $0.4 million, $1.9 million and $0.8 million, respectively, and is included as a reduction of interest expense, net in the statements of consolidated operations.
Asset Retirement Obligations: The Partnership operates and maintains its transmission and storage system and its gathering system, and intends to do so as long as supply and demand for natural gas exists, which is expected for the foreseeable future. Therefore, the Partnership believes that it cannot reasonably estimate the asset retirement obligations for its system assets as these assets have indeterminate lives.
Equity-Based Compensation: The Partnership has awarded equity-based compensation in connection with the EQT Midstream Services, LLC 2012 Long-Term Incentive Plan. These awards will be paid in units; therefore, the Partnership treats these programs as equity awards. Awards that have a fixed estimate due to a market condition require the Partnership to obtain a valuation. Significant assumptions made in valuing the Partnership’s awards include the market price of units at payout date, total unitholder return threshold to be achieved, volatility, risk-free rate, term, dividend yield and forfeiture rate.
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
Net Income per Limited Partner Unit: Net income per limited partner unit is calculated utilizing the two-class method by dividing the limited partner interest in net income by the weighted average number of limited partner units outstanding during the period. The Partnership’s net income is allocated to the general partner and limited partners, including subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the Partnership’s partnership agreement) for the period. Net income attributable to periods prior to the IPO and to the Sunrise Pipeline assets for periods prior to July 22, 2013 is not allocated to the limited partners for purposes of calculating net income per limited partner unit. Any common units issued during the period are included on a weighted-average basis for the days in which they were outstanding. Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the long-term incentive plan, were exercised, settled or converted into common units.
Income Taxes: Prior to the IPO, the Partnership’s income was included as part of EQT’s consolidated federal tax return. In conjunction with the contribution by EQT of the ownership of Equitrans to the Partnership immediately prior to the IPO, approximately $143.6 million of net current and deferred tax liabilities were eliminated through equity. Effective July 2, 2012, as a result of its limited partnership structure, the Partnership is a partnership for income tax purposes and no longer subject to federal and state income taxes. For federal and state income tax purposes, all income, expenses, gains, losses and tax credits generated flow through to the owners, and accordingly, do not result in a provision for income taxes for the Partnership. The income tax effects associated with Sunrise’s operations prior to the Sunrise Merger are reflected in the consolidated financial statements. Immediately prior to the Sunrise Merger, approximately $43.1 million of net current and deferred tax liabilities were eliminated through equity. Net income for financial statement purposes may differ significantly from taxable income of unitholders because of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Partnership’s partnership agreement. The aggregate difference in the basis of the Partnership’s net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes is not available to us.
Emerging Growth Company: Under the Jumpstart Our Business Startups Act (JOBS Act), for as long as the Partnership remains an ‘‘emerging growth company’’ as defined in the JOBS Act, the Partnership may take advantage of certain exemptions from Securities and Exchange Commission (SEC) reporting requirements that are applicable to other public companies that are not emerging growth companies. These exemptions include not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of its system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in the Partnership’s periodic reports and proxy statements, exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and seeking shareholder approval of any golden parachute payments not previously approved. The Partnership may take advantage of these reporting exemptions until the Partnership is no longer an emerging growth company. The Partnership will remain an emerging growth company for up to five years, although it will lose that status sooner if it has more than $1.0 billion of revenues in a fiscal year, the limited partner interests held by non-affiliates have a market value of more than $700 million at June 30 of any year, or the Partnership issues more than $1.0 billion of non-convertible debt over a three-year period.
The JOBS Act also provides that an emerging growth company can delay adopting new or revised accounting standards until such time as those standards apply to private companies. The Partnership has irrevocably elected to opt out of this exemption and, therefore, will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.
Subsequent Events: The Partnership has evaluated subsequent events through the date of the financial statement issuance.
2. Sunrise Merger
On July 15, 2013, the Partnership and Equitrans entered into an Agreement and Plan of Merger with EQT and Sunrise, a wholly owned subsidiary of EQT and the owner of the Sunrise Pipeline. Effective July 22, 2013,
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
Sunrise merged with and into Equitrans, with Equitrans continuing as the surviving company. Upon closing, the Partnership paid EQT consideration of $540 million, consisting of a $507.5 million cash payment, 479,184 Partnership common units and 267,942 Partnership general partner units. Prior to the Sunrise Merger, Equitrans entered into a precedent agreement with a third party for firm transportation service on the Sunrise Pipeline over a twenty-year term (the Precedent Agreement). Pursuant to the Agreement and Plan of Merger, following the effectiveness of the transportation agreement contemplated by the Precedent Agreement in December 2013, the Partnership was obligated to pay additional consideration of $110 million. The Partnership made this additional payment to EQT in January 2014.
Prior to the Sunrise Merger, the Partnership operated the Sunrise Pipeline as part of its transmission and storage system under a lease agreement with EQT. The lease was a capital lease under Generally Accepted Accounting Principles (GAAP); therefore, prior to the merger, revenues and expenses associated with Sunrise were included in the Partnership’s historical consolidated financial statements and the Sunrise Pipeline was depreciated over the lease term of 15 years. Effective as of the closing of the Sunrise Merger on July 22, 2013, the lease agreement was terminated.
The Sunrise Merger was a transaction between entities under common control. As a result, the Partnership was required to recast its financial statements to retrospectively reflect the Sunrise Merger. This included recasting depreciation expense recognized for the periods prior to the merger to reflect the pipeline’s useful life of 40 years. Also, the Partnership was required to record the assets and liabilities of Sunrise at their carrying amounts to EQT on the date of the merger. The $434.3 million difference between EQT’s net carrying amount of $215.7 million and the total consideration of $650 million was recorded as a capital transaction with EQT. As a result, this portion of the consideration was reported in financing activities in the statements of consolidated cash flows. In addition, because the effect of the recast of the financial statements resulted in the elimination of the capital lease obligation from the Partnership to Sunrise which was essentially equal to the carrying value of the assets and liabilities of Sunrise, the remaining consideration was also reported as a financing transaction in the statements of consolidated cash flows.
3. Financial Information by Business Segment
Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and is subject to evaluation by the chief operating decision maker in deciding how to allocate resources.
The Partnership reports its operations in two segments, which reflect its lines of business. Transmission and storage includes the Partnership’s FERC-regulated interstate pipeline and storage business. Gathering includes the FERC-regulated low pressure gathering system. The operating segments are evaluated on their contribution to the Partnership’s results based on operating income.
All of the Partnership’s operating revenues, income from operations and assets are generated or located in the United States.
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
|
|
|
Years Ended December 31, |
| ||||
|
|
|
2013 |
|
2012 |
|
2011 |
|
|
|
|
(Thousands) |
| ||||
|
Revenues from external customers: |
|
|
|
|
|
|
|
|
Transmission and storage |
$ |
173,881 |
$ |
120,797 |
$ |
93,707 |
|
|
Gathering |
|
12,010 |
|
16,113 |
|
15,906 |
|
|
Total |
$ |
185,891 |
$ |
136,910 |
$ |
109,613 |
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss): |
|
|
|
|
|
|
|
|
Transmission and storage |
$ |
124,950 |
$ |
81,127 |
$ |
60,906 |
|
|
Gathering |
|
(10,700) |
|
(5,976) |
|
(6,286 |
) |
|
Total operating income |
$ |
114,250 |
$ |
75,151 |
$ |
54,620 |
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of operating income to net income: |
|
|
|
|
|
|
|
|
Other income, net |
|
1,242 |
|
8,228 |
|
3,826 |
|
|
Interest expense, net |
|
1,672 |
|
2,944 |
|
5,050 |
|
|
Income tax expense |
|
4,053 |
|
17,313 |
|
20,807 |
|
|
Net income |
$ |
109,767 |
$ |
63,122 |
$ |
32,589 |
|
|
|
|
As of December 31, |
| ||
|
|
|
2013 |
|
2012 |
|
|
|
|
(Thousands) |
| ||
|
Segment assets: |
|
|
|
|
|
|
Transmission and storage |
$ |
828,053 |
$ |
678,437 |
|
|
Gathering |
|
84,960 |
|
75,200 |
|
|
Total assets |
$ |
913,013 |
$ |
753,637 |
|
As of December 31, 2011, transmission and storage and gathering had segment assets of $461.1 million and $85.4 million, respectively.
|
|
|
Years Ended December 31, |
| ||||
|
|
|
2013 |
|
2012 |
|
2011 |
|
|
|
|
(Thousands) |
| ||||
|
Depreciation and amortization: |
|
|
|
|
|
|
|
|
Transmission and storage |
$ |
18,323 |
$ |
12,901 |
$ |
8,850 |
|
|
Gathering |
|
2,867 |
|
2,839 |
|
2,620 |
|
|
Total |
$ |
21,190 |
$ |
15,740 |
$ |
11,470 |
|
|
|
|
|
|
|
|
|
|
|
Expenditures for segment assets: |
|
|
|
|
|
|
|
|
Transmission and storage |
$ |
77,989 |
$ |
188,143 |
$ |
131,902 |
|
|
Gathering |
|
5,031 |
|
5,379 |
|
3,929 |
|
|
Total |
$ |
83,020 |
$ |
193,522 |
$ |
135,831 |
|
4. Related-Party Transactions
In the ordinary course of business, the Partnership has transactions with affiliated companies. The Partnership has various contracts with affiliates including, but not limited to, transportation service and precedent agreements, storage agreements and gas gathering agreements.
Accounts receivable—affiliate represents amounts due from subsidiaries of EQT, primarily related to transmission, storage and gathering services. For the years ended December 31, 2013, 2012 and 2011, the Partnership generated revenues of approximately $142.4 million, $106.2 million and $86.6 million, respectively, from services provided to subsidiaries of EQT.
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
The accompanying consolidated balance sheets include amounts due from related parties of $6.5 million and $10.1 million as of December 31, 2013 and 2012, respectively. Amounts due to related parties as of December 31, 2013 and 2012, respectively, totaled $110.0 million and $1.3 million. Amounts due from related parties and amounts due to related parties represent transactions with subsidiaries of EQT other than transmission, storage and gathering services. See further discussion of the $110 million due to related parties for the Sunrise Merger in Note 2.
As discussed in Note 7, prior to the Partnership’s IPO, EQT provided financing to its subsidiaries directly or indirectly through EQT Capital Corporation (EQT Capital), EQT’s subsidiary finance company. This financing was predominantly through intercompany term and demand loans. The Partnership had demand and term notes due to EQT Capital of approximately $135.2 million which were repaid in June 2012. Interest expense on affiliate long-term debt and demand loans amounted to $0.0 million, $4.1 million and $5.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.
In addition, operating and administrative expenses and capital expenditures incurred on the Partnership’s behalf by EQT result in intercompany advances recorded as amounts due to EQT on the Partnership’s balance sheet. Prior to the IPO, these advances were related to changes in working capital, cash used for capital expenditures, as well as the Partnership’s cash flow needs. These amounts were viewed as financing transactions as the Partnership would have otherwise obtained demand notes or term loans from EQT Capital to fund them. Subsequent to the IPO, these transactions reflect services rendered on behalf of the Partnership by EQT and its affiliates for operating expenses as described in the following section and these amounts are settled monthly; therefore, they are classified as operating activities in the statements of consolidated cash flows.
Employees of EQT operate the Partnership’s assets. EQT charges the Partnership for the payroll and benefit costs associated with these individuals and for retirees of Equitrans. EQT carries the obligations for pension and other employee-related benefits in its consolidated financial statements. The Partnership is allocated a portion of EQT’s defined benefit pension plan and retiree medical and life insurance cost for the retirees of Equitrans based on an actuarial assessment of that cost. The Partnership’s share of those costs is recorded in due to related parties and reflected in operating and maintenance expense and selling, general and administrative expense in the accompanying statements of consolidated operations.
The Partnership is allocated the portion of the indirect operating and maintenance expense incurred by EQT and EQT Gathering which is related to the Partnership. For the years ended December 31, 2013, 2012 and 2011, operating and maintenance expenses allocated to the Partnership were approximately $4.7 million, $3.4 million and $2.5 million, respectively. The allocations were primarily based on a calculation of the Partnership’s percentage of net plant, revenue and headcount. EQT management believes allocating these expenses to the Partnership was necessary and appropriate. The increase in 2013 is attributable to the Partnership expansion efforts.
For the years ended December 31, 2013, 2012 and 2011, selling, general and administrative expenses of EQT and EQT Gathering allocated to the Partnership were approximately $7.1 million, $4.6 million and $3.7 million, respectively, based on a calculation of its percentage of net plant, revenue and headcount.
The historical financial statements of the Predecessor include long-term incentive compensation plan expenses associated with the EQT long-term incentive plan, which is not an expense of the Partnership subsequent to the IPO. See Note 10 for discussion of the Partnership’s equity-based compensation plan. EQT’s share-based compensation programs consist of restricted stock, stock options and performance-based units issued to employees. To the extent compensation related to individuals directly involved in the Partnership’s transmission and storage or gathering operations, such amounts were allocated to the Partnership by EQT and were reflected as operating and maintenance expenses. Such amounts totaled $1.9 million and $3.1 million for the years ended December 31, 2012 and 2011, respectively.
On December 19, 2012, EQT and a direct wholly owned subsidiary entered into a Master Purchase Agreement with PNG Companies LLC (PNG Companies), to transfer 100% ownership of EQT’s local distribution company, Equitable Gas Company, LLC (Equitable Gas Company) to PNG Companies (the Equitable Gas Transaction). The parties completed the Equitable Gas Transaction on December 17, 2013. As a result, revenues related to Equitable Gas Company will be reported as third party revenues in 2014 rather than EQT affiliate
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
revenues. For the years ended December 31, 2013, 2012 and 2011, Equitable Gas Company accounted for approximately 21%, 27% and 35%, respectively, of the Partnership’s total revenues.
Agreements with EQT
The Partnership and other parties have entered into various agreements with EQT, as summarized below. These agreements were negotiated in connection with the IPO.
Omnibus Agreement
The Partnership entered into an omnibus agreement by and among the Partnership, its general partner and EQT. Pursuant to the omnibus agreement, EQT agreed to provide the Partnership with a license to use the name “EQT” and related marks in connection with the Partnership’s business. The omnibus agreement also provides for certain indemnification and reimbursement obligations between EQT and the Partnership.
As more fully described in the omnibus agreement, the following matters are addressed:
· the Partnership’s obligation to reimburse EQT and its affiliates for certain direct operating expenses they pay on the Partnership’s behalf;
· the Partnership’s obligation to reimburse EQT and its affiliates for providing the Partnership corporate, general and administrative services and providing the Partnership operation and management services pursuant to the operation and management services agreement;
· EQT’s obligation to indemnify or reimburse the Partnership for losses or expenses relating to or arising from (i) certain plugging and abandonment obligations; (ii) certain bare steel replacement capital expenditures; (iii) certain pipeline safety costs; (iv) certain preclosing environmental liabilities; (v) certain title and rights-of-way matters; (vi) the Partnership’s failure to have certain necessary governmental consents and permits; (vii) certain preclosing tax liabilities; (viii) assets previously owned by Equitrans, but retained by EQT and its affiliates following the IPO, including the Sunrise Pipeline; (ix) any claims related to Equitrans’ previous ownership of the Big Sandy Pipeline; and (x) any amounts owed to the Partnership by a third party that has exercised a contractual right of offset against amounts owed by EQT to such third party; and
· the Partnership’s obligation to indemnify EQT for losses attributable to (i) the ownership or operation of the Partnership’s assets after the closing of the IPO, except to the extent EQT is obligated to indemnify the Partnership for such losses pursuant to the operation and management services agreement with EQT, and (ii) any amounts owed to EQT by a third party that has exercised a contractual right of offset against amounts owed by the Partnership to such third party.
For the year ended December 31, 2013, the Partnership was obligated to reimburse EQT for approximately $14.3 million for operating and maintenance expenses and approximately $18.3 million for selling, general and administrative expenses pursuant to the omnibus agreement. In 2012 for the post-IPO period of July 2, 2012 to December 31, 2012, the Partnership was obligated to reimburse EQT for approximately $8.5 million of operating and maintenance expenses and approximately $7.7 million of selling, general and administrative expenses pursuant to the omnibus agreement.
For the year ended December 31, 2013, EQT was obligated to reimburse the Partnership pursuant to the omnibus agreement for $0.6 million related to plugging and abandonment liabilities and $2.6 million related to bare steel replacement. In 2012 for the post-IPO period of July 2, 2012 to December 31, 2012, EQT was obligated to reimburse the Partnership pursuant to the omnibus agreement for $1.6 million related to plugging and abandonment liabilities, $2.7 million related to bare steel replacement and $2.7 million related to Big Sandy Pipeline claims.
Operation and Management Services Agreement
The Partnership entered into an operation and management services agreement with EQT Gathering, pursuant to which EQT Gathering will provide the Partnership’s pipelines and storage facilities with certain operational and management services. The Partnership will reimburse EQT Gathering for such services pursuant to the terms of the omnibus agreement as described above.
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
Under the operation and management services agreement, EQT Gathering will indemnify the Partnership with respect to claims, losses or liabilities incurred by the Partnership, including third party claims, arising out of EQT Gathering’s gross negligence or willful misconduct. The Partnership will indemnify EQT Gathering from any claims, losses or liabilities incurred by EQT Gathering, including any third-party claims, arising from the performance of the agreement, but not to the extent of losses or liabilities caused by EQT Gathering’s gross negligence or willful misconduct.
5. Income Taxes
The Partnership’s financial statements for the period prior to the IPO include U.S. federal and state income tax as its income was included as part of EQT’s consolidated federal tax return. In conjunction with the contribution by EQT of the ownership of Equitrans to the Partnership immediately prior to the IPO, approximately $143.6 million of net current and deferred income tax liabilities were eliminated through equity. Effective July 2, 2012, as a result of its limited partnership structure, the Partnership is no longer subject to federal and state income taxes. For federal and state income tax purposes, all income, expenses, gains, losses and tax credits generated flow through to the owners, and accordingly, do not result in a provision for income taxes for the Partnership.
As discussed in Note 2, the Partnership completed the Sunrise Merger on July 22, 2013. This was a transaction between entities under common control and required the Partnership to recast its financial statements to retrospectively reflect the Sunrise Merger. Prior to this transaction, Sunrise’s income was included as part of EQT’s consolidated federal tax return; therefore, Sunrise’s financial statements included U.S. federal and state income tax. Accordingly, the income tax effects associated with Sunrise’s operations prior to the Sunrise Merger are reflected in the consolidated financial statements. In the third quarter of 2013, in connection with the Sunrise Merger and the resulting change in tax status of Sunrise, approximately $43.1 million of net current and deferred income tax liabilities were eliminated through equity.
The components of the federal income tax expense (benefit) for the years ended December 31, 2013, 2012 and 2011 are as follows:
|
|
|
Years Ended December 31, |
| ||||
|
|
|
2013 |
|
2012 |
|
2011 |
|
|
|
|
(Thousands) |
| ||||
|
Current: |
|
|
|
|
|
|
|
|
Federal |
$ |
3,909 |
$ |
(34,500) |
$ |
6,473 |
|
|
State |
|
406 |
|
2,699 |
|
2,026 |
|
|
Subtotal |
|
4,315 |
|
(31,801) |
|
8,499 |
|
|
Deferred: |
|
|
|
|
|
|
|
|
Federal |
|
(573) |
|
46,604 |
|
9,849 |
|
|
State |
|
311 |
|
2,601 |
|
2,657 |
|
|
Subtotal |
|
(262) |
|
49,205 |
|
12,506 |
|
|
Amortization of deferred investment tax credit |
|
— |
|
(91) |
|
(198 |
) |
|
Total |
$ |
4,053 |
$ |
17,313 |
$ |
20,807 |
|
Prior to the IPO, in the case of the Partnership, and the Sunrise Merger, in the case of Sunrise, tax obligations were transferred to EQT. EQT’s consolidated federal income tax was allocated among the group’s members on a separate return basis with tax credits allocated to the members generating the credits. The current federal tax benefit recorded in 2012 relates to cash refunds received during the year from EQT for its use of Sunrise’s tax bonus depreciation deductions. The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Relief Act) increased bonus depreciation from 50% to 100% for qualified investments made after September 8, 2010 and before January 1, 2012, which includes the Sunrise Pipeline. The Sunrise Pipeline lease was treated as an operating lease for income tax purposes; therefore, EQT was able to elect bonus depreciation for the Sunrise Pipeline, which was included in its consolidated federal tax return.
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
Income tax expense differed from amounts computed at the federal statutory rate of 35% on pre-tax book income from continuing operations as follows:
|
|
|
Years Ended December 31, |
| ||||
|
|
|
2013 |
|
2012 |
|
2011 |
|
|
|
|
(Thousands) |
| ||||
|
Tax at statutory rate |
$ |
39,837 |
$ |
28,152 |
$ |
18,689 |
|
|
Partnership income not subject to income taxes |
|
(36,253) |
|
(12,623) |
|
— |
|
|
State income taxes |
|
466 |
|
2,197 |
|
3,044 |
|
|
Unrecognized tax benefits |
|
— |
|
1,248 |
|
— |
|
|
Regulatory assets |
|
3 |
|
(1,491) |
|
(1,057) |
|
|
Other |
|
— |
|
(170) |
|
131 |
|
|
Income tax expense |
$ |
4,053 |
$ |
17,313 |
$ |
20,807 |
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate |
|
3.6% |
|
21.5% |
|
39.0% |
|
As previously noted, the Sunrise Merger on July 22, 2013 was a transfer between entities under common control for which the financial statements of the Partnership have been retrospectively recast to reflect the combined entities. Accordingly, the income tax effects associated with Sunrise’s operations prior to the Sunrise Merger are reflected in the consolidated financial statements as Sunrise was previously part of EQT’s consolidated federal tax return. The decrease in income tax expense in 2013 and 2012 resulted from these changes in the tax status.
The Partnership’s historical uncertain tax positions were immaterial and were attributable to periods prior to the IPO or attributable to Sunrise for periods prior to the Sunrise Merger. Additionally, EQT has indemnified the Partnership for these historical tax positions; therefore, the Partnership does not anticipate any future liabilities arising from these uncertain tax positions.
The following table summarizes the source and tax effects of temporary differences between financial reporting and tax basis of assets and liabilities:
|
|
|
December 31, |
|
|
|
|
2012 |
|
|
|
|
(Thousands) |
|
|
Deferred income taxes: |
|
|
|
|
Total deferred income tax assets |
$ |
(33,881) |
|
|
Total deferred income tax liabilities |
|
74,723 |
|
|
Total net deferred income tax liabilities |
$ |
40,842 |
|
|
|
|
|
|
|
Total deferred income tax (assets)/liabilities: |
|
|
|
|
PP&E tax deductions in excess of book deductions |
$ |
74,723 |
|
|
Net operating loss carryforwards |
|
(32,853) |
|
|
Other |
|
(1,028) |
|
|
Total net deferred income tax liabilities |
$ |
40,842 |
|
At December 31, 2012, there was no valuation allowance relating to deferred tax assets as the entire balance was expected to be realized. The deferred tax liabilities principally consisted of temporary differences between financial and tax reporting for the Partnership’s property, plant and equipment (PP&E).
Under the omnibus agreement, EQT has indemnified the Partnership from and against any losses suffered or incurred by the Partnership and related to or arising out of or in connection with any federal, state or local income tax liabilities attributable to the ownership or operation of the Partnership Assets (as defined in the Partnership Agreement) prior to the closing of the IPO. Under the terms of the Agreement and Plan of Merger for the Sunrise Merger, EQT has indemnified the Partnership from and against any losses suffered or incurred by the Partnership and related to or arising out of or in connection with any federal, state or local income tax liabilities attributable to the ownership or operation of the Sunrise assets (as defined in the Agreement and Plan of Merger) prior to the
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
closing of the Sunrise Merger. Therefore, the Partnership does not anticipate any future liabilities arising from the historical deferred tax liabilities.
6. Regulatory Assets and Liabilities
Regulatory assets are recoverable or reimbursable over various periods and do not earn a return on investment. The Partnership believes that it will continue to be subject to rate regulation that will provide for the recovery of its regulatory assets. Regulatory liabilities are included in other long-term liabilities in the accompanying consolidated balance sheets.
The regulatory asset associated with deferred taxes of $14.1 million and $14.7 million as of December 31, 2013 and 2012, respectively, primarily represents deferred income taxes recoverable through future rates related to a historical deferred tax position and the equity component of AFUDC. The Partnership expects to recover the amortization of the deferred tax position ratably over the corresponding life of the underlying assets that created the difference. The deferred tax regulatory asset associated with AFUDC represents the offset to the deferred taxes associated with the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes will be collected through rates over the depreciable lives of the long-lived assets to which they relate. The amounts established for deferred taxes were primarily generated during the pre-IPO period when the Partnership was included as part of EQT’s consolidated federal tax return. Effective July 2, 2012, the Partnership is a partnership for income tax purposes and no longer subject to federal and state income taxes.
The Partnership defers expenses for on-going post-retirement benefits other than pensions which are subject to recovery in approved rates. The regulatory liability as of December 31, 2013 of $3.7 million reflects lower cumulative actuarial expenses than the amounts recovered through rates, which could be subject to reimbursement to customers in the next rate case. As of December 31, 2012, the regulatory asset was $3.2 million. The overall decrease in the regulatory asset related to post-retirement benefits other than pensions was the result of a change in the actuarially-determined allocation of the benefit obligation between EQT entities.
The regulatory asset associated with other recoverable costs was $2.2 million and $0.3 million as of December 31, 2013 and 2012, respectively, and primarily relates to the recovery of storage base gas.
7. Debt
As of December 31, 2013, the Partnership had a $350 million credit facility that would have expired on July 2, 2017. The Partnership did not have any short-term loans outstanding at any time during the years ended December 31, 2013 and 2012. In January 2014, the Partnership borrowed $110 million on its credit facility to make the additional payment to EQT related to the Sunrise Merger. For the years ended December 31, 2013 and 2012, commitment fees of approximately $0.9 million and $0.4 million, respectively, were paid to maintain credit availability under the Partnership’s credit facility at an annual rate of 25 basis points. As of December 31, 2013, the Partnership was in compliance with all debt provisions and covenants.
In February 2014, the Partnership amended its credit facility to increase the borrowing capacity to $750 million. The amended credit facility will expire in February 2019. The credit facility is available to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions and to repurchase units and for general partnership purposes. Subject to certain terms and conditions, the credit facility has an accordion feature that allows the Partnership to increase the available borrowings under the facility by up to an additional $250 million. In addition, the credit facility includes a sublimit up to $75 million for same-day swing line advances and a sublimit up to $150 million for letters of credit. Further, the Partnership has the ability to request that one or more lenders make term loans to it under the credit facility subject to the satisfaction of certain conditions, which term loans will be secured by cash and qualifying investment grade securities. The Partnership’s obligations under the revolving portion of the credit facility are unsecured.
The Partnership’s credit facility contains various provisions that, if not complied with, could result in termination of the credit facility, require early payment of amounts outstanding or similar actions. The most
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
significant covenants and events of default under the credit facility relate to maintenance of permitted leverage ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. Under the credit facility, the Partnership is required to maintain a consolidated leverage ratio of not more than 5.00 to 1.00 (or, after the Partnership obtains an investment grade rating, not more than 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions).
Prior to the IPO, EQT provided financing to the Partnership directly or indirectly through EQT Capital. Such financing was generally provided through intercompany term and demand loans that were entered into between EQT Capital and EQT’s subsidiaries. On June 21, 2012, the term note of $135.2 million was retired.
8. Pension and Other Postretirement Benefit Plans
Employees of EQT operate the Partnership’s assets. EQT charges the Partnership for the payroll and benefit costs associated with these individuals and for retirees of Equitrans. EQT carries the obligations for pension and other employee-related benefits in its financial statements.
Equitrans’ retirees participate in a defined benefit pension plan that is sponsored by EQT. For the years ended December 31, 2013, 2012 and 2011, the Partnership reimbursed EQT approximately $0.3 million per year in order to meet certain funding targets. The Partnership expects to make cash payments to EQT of approximately $0.2 million in 2014 to reimburse for defined benefit pension plan funding. Pension plan contributions are designed to meet minimum funding requirements and keep plan assets at least equal to 80% of projected liabilities. The Partnership’s reimbursements to EQT are based on the proportion of the plan’s total liabilities allocable to Equitrans retirees. For the years ended December 31, 2013, 2012 and 2011, the Partnership was allocated $0.1 million per year of the expenses associated with the plan. The dollar amount of a cash reimbursement to EQT in any particular year will vary as a result of gains or losses sustained by the pension plan assets during the year due to market conditions. The Partnership does not expect the variability of contribution requirements to have a significant effect on its business, financial condition, results of operations, liquidity or ability to make distributions.
The Partnership contributes to a defined contribution plan sponsored by EQT. The contribution amount is a percentage of allocated base salary. In 2013, 2012 and 2011, there were no direct contributions but the Partnership was charged through the EQT payroll and benefit costs discussed in Note 4.
The individuals who operate the Partnership’s assets and Equitrans retirees participate in certain other post-employment benefit plans sponsored by EQT. The Partnership was allocated $0.1 million, $0.3 million and $0.3 million in 2013, 2012 and 2011, respectively, of the expenses associated with these plans.
Under the July 1, 2005 Equitrans rate case settlement, the Partnership began amortizing post-retirement benefits other than pensions previously deferred over a five-year period. Currently, the Partnership recognizes expenses for ongoing post-retirement benefits other than pensions, which are now subject to recovery in the approved rates. Expenses recognized by the Partnership for the years ended December 31, 2013, 2012 and 2011 for ongoing post-retirement benefits other than pensions were approximately $1.2 million per year.
9. Net Income per Limited Partner Unit and Cash Distributions
The Partnership’s net income is allocated to the general partner and limited partners, including subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the Partnership’s partnership agreement) for the period. Net income allocated to the general partner for the year ended December 31, 2013 includes amounts attributed to incentive distributions. The Partnership’s net income allocable to the limited partners is allocated between common and subordinated unitholders by applying the provisions of the Partnership’s partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed. Any common units issued during the period are included on a weighted-average basis for the days in which they were outstanding.
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the long-term incentive plan, were exercised, settled or converted into common units. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted net income per limited partner unit calculation, the impact is reflected by applying the treasury stock method. Potentially dilutive securities, consisting of performance awards and phantom units, included in the calculation of diluted net income per limited partner unit totaled 108,113 and 54,938 for the years ended December 31, 2013 and 2012, respectively.
The following table presents the Partnership’s calculation of net income per limited partner unit for common and subordinated limited partner units. Net income attributable to periods prior to the IPO and to the Sunrise Pipeline assets for periods prior to July 22, 2013 is not allocated to the limited partners for purposes of calculating net income per limited partner unit.
|
|
|
Years Ended December 31, |
| ||
|
|
|
2013 |
|
2012 |
|
|
|
|
(Thousands, except per unit data) |
| ||
|
Net income |
$ |
109,767 |
$ |
63,122 |
|
|
Less: |
|
|
|
|
|
|
Pre-acquisition net income allocated to parent |
|
(6,189) |
|
(26,563) |
|
|
General partner interest in net income – 2% |
|
(2,140) |
|
(791) |
|
|
General partner interest in net income attributable to incentive distribution rights |
|
(787) |
|
— |
|
|
Limited partner interest in net income |
$ |
100,651 |
$ |
35,768 |
|
|
|
|
|
|
|
|
|
Net income allocable to common units |
$ |
58,673 |
$ |
16,345 |
|
|
Net income allocable to subordinated units |
|
41,978 |
|
19,423 |
|
|
Limited partner interest in net income |
$ |
100,651 |
$ |
35,768 |
|
|
|
|
|
|
|
|
|
Weighted average limited partner units outstanding – basic |
|
|
|
|
|
|
Common units |
|
23,399 |
|
17,339 |
|
|
Subordinated units |
|
17,340 |
|
17,340 |
|
|
Total |
|
40,739 |
|
34,679 |
|
|
|
|
|
|
|
|
|
Weighted average limited partner units outstanding – diluted |
|
|
|
|
|
|
Common units |
|
23,507 |
|
17,394 |
|
|
Subordinated units |
|
17,340 |
|
17,340 |
|
|
Total |
|
40,847 |
|
34,734 |
|
|
|
|
|
|
|
|
|
Net income per limited partner unit – basic |
|
|
|
|
|
|
Common units |
$ |
2.51 |
$ |
0.94 |
|
|
Subordinated units |
|
2.42 |
|
1.12 |
|
|
Total |
$ |
2.47 |
$ |
1.03 |
|
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
|
|
|
Years Ended December 31, |
| ||
|
|
|
2013 |
|
2012 |
|
|
|
|
(Thousands, except per unit data) |
| ||
|
Net income per limited partner unit – diluted |
|
|
|
|
|
|
Common units |
$ |
2.50 |
$ |
0.94 |
|
|
Subordinated units |
|
2.42 |
|
1.12 |
|
|
Total |
$ |
2.46 |
$ |
1.03 |
|
The partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ended September 30, 2012, the Partnership distribute all of its available cash (described below) to unitholders of record on the applicable record date. As further discussed in Note 16, a quarterly cash distribution was declared on January 23, 2014 and paid on February 14, 2014 to unitholders of record on February 4, 2014.
Available cash
Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
• less, the amount of cash reserves established by the Partnership’s general partner to:
• provide for the proper conduct of the Partnership’s business (including reserves for future capital expenditures, anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);
• comply with applicable law, any of the Partnership’s debt instruments or other agreements; or
• provide funds for distributions to the Partnership’s unitholders and to the Partnership’s general partner for any one or more of the next four quarters (provided that the Partnership’s general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent the Partnership from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);
• plus, if the Partnership’s 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.
Subordinated Units
All subordinated units are held by EQT. The Partnership’s partnership agreement provides that, during the period of time referred to as the “subordination period,” the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.35 per common unit (the minimum quarterly distribution, as defined in the Partnership’s partnership agreement) plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to distribute the minimum quarterly distribution to the common units. The subordination period will end and the subordinated units will convert to common units on a one-for-one basis when certain distribution requirements, as defined in the Partnership’s partnership agreement, have been met.
Incentive Distribution Rights
All incentive distribution rights are held by the Partnership’s general partner. Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels described below have been achieved. The Partnership’s general partner may transfer the incentive distribution rights separately from its general partner interest, subject to restrictions in the Partnership’s partnership agreement.
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
The following discussion assumes that the Partnership’s general partner continues to own both its 2.0% general partner interest and the incentive distribution rights.
If for any quarter:
• the Partnership has distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
• the Partnership has distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;
then, the Partnership will distribute any additional available cash from operating surplus for that quarter among the unitholders and the Partnership’s general partner in the following manner:
|
|
|
Total Quarterly |
|
Marginal Percentage Interest in |
| ||
|
|
|
Unit Target Amount |
|
Unitholders |
|
General Partner |
|
|
Minimum Quarterly Distribution |
|
$0.3500 |
|
98.0% |
|
2.0% |
|
|
First Target Distribution |
|
Above $0.3500 up to $0.4025 |
|
98.0% |
|
2.0% |
|
|
Second Target Distribution |
|
Above $0.4025 up to $0.4375 |
|
85.0% |
|
15.0% |
|
|
Third Target Distribution |
|
Above $0.4375 up to $0.5250 |
|
75.0% |
|
25.0% |
|
|
Thereafter |
|
Above $0.5250 |
|
50.0% |
|
50.0% |
|
To the extent these incentive distributions are made to the general partner, more available cash proportionally is allocated to the general partner than to holders of common and subordinated units. In connection with the Partnership’s cash distribution paid on February 14, 2014, EQT received approximately $0.6 million related to its incentive distribution rights.
10. Equity-Based Compensation Plan
Equity-based compensation expense recorded by the Partnership was $1.0 million and $0.5 million for the years ended December 31, 2013 and 2012, respectively.
At the closing of the IPO in July 2012, the Partnership’s general partner granted performance awards representing 146,490 common units, all of which were outstanding as of January 1, 2013. These awards have a performance condition related to the total unitholder return realized on the Partnership’s common units from the IPO through December 31, 2015. If earned, the units are expected to be distributed in Partnership common units. The Partnership accounted for these awards as equity awards using the $20.02 grant date fair value as determined using a fair value model. The price was generated using annual historical volatility of peer-group companies for the expected term of the awards, which is based upon the performance period. The range of expected volatilities calculated by the valuation model was 27% - 72% and the weighted-average expected volatility was 38%. Additional assumptions included the risk-free rate for periods within the contractual life of the awards based on the U.S. Treasury yield curve in effect at the time of grant and an expected dividend growth rate of 10%. Adjusting for 3,990 forfeitures, there were 142,500 performance awards outstanding as of December 31, 2013. As of December 31, 2013, there was $1.7 million of total unrecognized compensation cost related to these performance awards which is expected to be recognized over a period of two years.
The Partnership’s general partner has granted equity-based phantom units that vested upon grant to the independent directors of its general partner. The value of the phantom units will be paid in common units on a director’s termination of service on the general partner’s Board of Directors. The Partnership accounted for these awards as equity awards and recorded compensation expense for the fair value of the awards at the grant date fair value. A total of 8,886 independent director unit-based awards including accrued distributions were outstanding as
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
of December 31, 2013. A total of 3,790 and 4,780 unit-based awards were granted to the independent directors during the years ended December 31, 2013 and 2012, respectively. The weighted average fair value of these grants, based on the Partnership’s common unit price on the grant date, was $37.92 and $24.30 for the years ended December 31, 2013 and 2012, respectively.
Common units to be delivered pursuant to vesting of the equity based awards may be common units acquired by the Partnership’s general partner in the open market, from any other person, directly from the Partnership or any combination of the foregoing.
See also Note 4 for discussion of the EQT long-term incentive plan for periods prior to the IPO.
In the first quarter of 2014, 32,840 performance units were granted to EQT employees who provide services to the Partnership under the 2014 EQM Value Driver Award (2014 EQM VDA). Fifty percent of the units confirmed under the 2014 EQM VDA will vest upon the payment date following the first anniversary of the grant date; the remaining fifty percent will vest upon the payment date following the second anniversary of the grant date. The payout will vary between zero and 300% of the number of units granted contingent upon the Partnership’s 2014 adjusted earnings before interest, taxes, depreciation and amortization performance as compared to its annual business plan and individual, business unit and Partnership value driver performance over the period January 1, 2014 through December 31, 2014. If earned, the 2014 EQM VDA units are expected to be paid in Partnership common units. The Partnership did not record any expense related to the 2014 EQM VDA as of December 31, 2013.
11. Lease Obligations
On December 17, 2013, the Partnership entered into a lease with EQT for the AVC facilities. Under the lease, the Partnership operates the facilities as part of its transmission and storage system under the rates, terms and conditions of its FERC-approved tariff. The AVC facilities are strategically located to connect the Marcellus supply and demand and include an approximately 200 mile pipeline that interconnects with the Partnership’s transmission and storage system. Additionally, the AVC facilities provide 450 BBtu per day of additional firm capacity to the Partnership’s system and are supported by 4 associated natural gas storage reservoirs with approximately 260 MMcf per day of peak withdrawal capability and 15 Bcf of working gas capacity. Of the total 15 Bcf of working gas capacity, the Partnership leases and operates 13 Bcf of working gas capacity. The lease payment due each month is the lesser of the following alternatives: (1) a revenue-based payment reflecting the revenues generated by the operation of AVC minus the actual costs of operating AVC and (2) a payment based on depreciation expense and pre-tax return on invested capital for AVC. As a result, the payments to be made under the AVC lease will be variable.
Management determined that the AVC lease was a capital lease under GAAP. The gross capital lease assets and obligations recorded in 2013 were approximately $134.4 million. The Partnership expects modernization capital expenditures will be incurred to upgrade the AVC assets. Under the terms of the lease agreement, the Partnership will be reimbursed for all modernization capital expenditures. As the capital expenditures are incurred, the capital lease asset and obligations will increase.
For the year ended December 31, 2013, interest expense of $0.8 million and depreciation expense of $0.4 million were recorded related to the capital lease. At December 31, 2013, accumulated depreciation was $0.4 million, net capital lease assets were $134.0 million and capital lease obligations were $134.4 million.
The following is a schedule of the estimated future minimum lease payments under the capital lease together with the present value of the net minimum lease payments as of December 31, 2013:
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
|
|
|
Year ending |
|
|
|
|
(Thousands) |
|
|
2014 |
$ |
16,650 |
|
|
2015 |
|
15,164 |
|
|
2016 |
|
18,200 |
|
|
2017 |
|
20,477 |
|
|
2018 |
|
20,214 |
|
|
Later years |
|
322,807 |
|
|
Total minimum lease payments(a) |
$ |
413,512 |
|
|
Less: Amount representing interest(b) |
|
(279,117) |
|
|
Present value of net minimum lease payments |
$ |
134,395 |
|
|
|
|
(a) There were no amounts representing contingent rentals or executory costs (such as taxes, maintenance and insurance) included in the total minimum lease payments. |
|
(b) Amount necessary to reduce net minimum lease payments to the fair value of the property at December 31, 2013 as the present value calculated at the Partnership’s incremental borrowing rate exceeded the fair value of the property at inception of the lease. |
12. Concentrations of Credit Risk
The Partnership’s transmission and storage and gathering operations include FERC-regulated interstate pipelines and storage service for Equitable Gas Company, LLC, which was previously a subsidiary of EQT Corporation, as well as other utility and end users customers located in the northeastern United States. The Partnership also provides service to customers engaged in commodity procurement and delivery, including large industrial, utility, commercial and institutional customers and certain marketers primarily in the Appalachian and mid-Atlantic regions.
Approximately 59% and 87% of third party accounts receivable balances of $8.5 million and $3.7 million as of December 31, 2013 and 2012, respectively, represent amounts due from marketers. The Partnership manages the credit risk of sales to marketers by limiting the Partnership’s dealings to those marketers that meet specified criteria for credit and liquidity strength and by actively monitoring these accounts. The Partnership may request a letter of credit, guarantee, performance bond or other credit enhancement from a marketer in order for that marketer to meet the Partnership’s credit criteria. The Partnership did not experience any significant defaults on accounts receivable during the years ended December 31, 2013, 2012 and 2011.
13. Commitments and Contingencies
The Partnership is subject to federal, state and local environmental laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and in certain instances result in assessment of fines. The Partnership has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, when recoverable through regulated rates, certain of these costs are deferred as regulatory assets. Ongoing expenditures for compliance with environmental law and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either nature or amount in the future and does not know of any environmental liabilities that will have a material effect on its business, financial condition, results of operations, liquidity or ability to make distributions.
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Partnership. While the amounts claimed may be substantial, the Partnership is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Partnership accrues legal or other direct costs related to loss contingencies when actually incurred. The Partnership has established reserves it believes to be appropriate for pending matters and after consultation with counsel and giving appropriate consideration to available insurance, the Partnership believes that the ultimate outcome of any matter currently pending against the
EQT MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2013
Partnership will not materially affect its business, financial condition, results of operations, liquidity or ability to make distributions.
14. Interim Financial Information (Unaudited)
The following quarterly summary of operating results reflects variations due primarily to growth in the transmission and storage business and the seasonal nature of the Partnership’s utility customer contracts.
|
|
|
Three months ended |
| ||||||
|
|
|
March 31 |
|
June 30 |
|
September 30 |
|
December 31 |
|
|
|
|
(Thousands, except per share amounts) |
| ||||||
|
2013 (a) |
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
$ |
44,365 |
$ |
44,837 |
$ |
45,882 |
$ |
50,807 |
|
|
Operating income |
|
28,429 |
|
26,814 |
|
27,593 |
|
31,414 |
|
|
Net income |
|
26,789 |
|
24,510 |
|
27,716 |
|
30,752 |
|
|
Net income per limited partner unit: |
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
0.68 |
$ |
0.59 |
$ |
0.61 |
$ |
0.62 |
|
|
Diluted |
$ |
0.68 |
$ |
0.59 |
$ |
0.60 |
$ |
0.62 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 (a) |
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
$ |
31,003 |
$ |
29,665 |
$ |
34,452 |
$ |
41,790 |
|
|
Operating income |
|
16,392 |
|
15,986 |
|
16,474 |
|
26,299 |
|
|
Net income |
|
11,123 |
|
11,639 |
|
15,958 |
|
24,402 |
|
|
Net income per limited partner unit (b): |
|
|
|
|
|
|
|
|
|
|
Basic |
|
N/A |
|
N/A |
$ |
0.40 |
$ |
0.63 |
|
|
Diluted |
|
N/A |
|
N/A |
$ |
0.40 |
$ |
0.63 |
|
(a) The sum of the quarterly data in some cases may not equal the yearly total due to rounding.
(b) Presented for post-IPO period only.
15. Subsidiary Guarantors
The Partnership filed a registration statement on Form S-3 with the SEC on July 1, 2013 to register, among other securities, debt securities. Certain subsidiaries of the Partnership (Subsidiary Guarantors) are co-registrants with the Partnership, and the registration statement registered guarantees of debt securities by one or more of the Subsidiary Guarantors (other than EQT Midstream Finance Corporation, a 100% owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of debt securities). The Subsidiary Guarantors are 100% owned by the Partnership and any guarantees by the Subsidiary Guarantors will be full and unconditional. Subsidiaries of the Partnership other than the Subsidiary Guarantors and EQT Midstream Finance Corporation are minor. The Partnership has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Partnership by dividend or loan. In the event that more than one of the Subsidiary Guarantors provide guarantees of any debt securities issued by the Partnership, such guarantees will constitute joint and several obligations. None of the assets of the Partnership or the Subsidiary Guarantors represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended.
16. Subsequent Events
On January 23, 2014, the Partnership announced that the Board of Directors of its general partner declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2013 of $0.46 per common and subordinated unit, $0.4 million to the general partner related to its 2% general partner interest and $0.6 million to the general partner related to its incentive distribution rights. The cash distribution will be paid on February 14, 2014 to unitholders of record at the close of business on February 4, 2014.
See Note 7 for discussion regarding the amended credit facility and borrowings subsequent to December 31, 2013.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of management of the Partnership’s general partner, including the general partner’s Principal Executive Officer and Principal Financial Officer, an evaluation of the Partnership’s disclosure controls and procedures (as defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officer of the Partnership’s general partner concluded that the Partnership’s disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Control over Financial Reporting
There were no changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
The management of the Partnership’s general partner is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s internal control system is designed to provide reasonable assurance to the Partnership’s management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.
The management of the Partnership’s general partner assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2013. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (1992). Based on this assessment, management concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2013.
This annual report on Form 10-K for the fiscal period ended December 31, 2013 does not include an auditor attestation report on our internal controls over financial reporting inasmuch as no attestation report was required under the rules of the Securities and Exchange Commission applicable to us as in effect at the time of filing.
Not Applicable.
Item 10. Directors, Executive Officers and Corporate Governance
Directors and Executive Officers of the Partnership’s General Partner
The Partnership is managed and operated by the directors and officers of its general partner, EQT Midstream Services, LLC. The directors of the Partnership’s general partner are appointed by EQT, and unitholders are not entitled to elect the directors of the general partner or directly or indirectly participate in the Partnership’s management or operations. The board of directors of the Partnership’s general partner has seven directors, of which three members are independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a publicly traded limited partnership like the Partnership to have a majority of independent directors on the board of directors of its general partner or to establish a compensation or a nominating and corporate governance committee.
Executive officers of the Partnership’s general partner manage the day-to-day affairs of the Partnership’s business and conduct the Partnership’s operations. All of the executive officers of the Partnership’s general partner are employees of EQT and devote such portion of their productive time to the Partnership’s business and affairs as is required to manage and conduct the Partnership’s operations. Pursuant to the terms of the omnibus agreement among the Partnership, its general partner and EQT, the Partnership is required to reimburse EQT for (i) allocated expenses of personnel who perform services for the Partnership’s benefit, and (ii) allocated general and administrative expenses. Please read Item 13, “Certain Relationships and Related Transactions, and Director Independence – Agreements with EQT – Omnibus Agreement.”
The executive officers and directors of the Partnership’s general partner as of February 20, 2014 are as follows:
|
Name |
|
Age |
|
Position with EQT Midstream Services, LLC |
|
David L. Porges |
|
56 |
|
Chairman, President and Chief Executive Officer |
|
Philip P. Conti |
|
54 |
|
Director, Senior Vice President and Chief Financial Officer |
|
Randall L. Crawford |
|
51 |
|
Director, Executive Vice President and Chief Operating Officer |
|
Lewis B. Gardner |
|
56 |
|
Director |
|
Theresa Z. Bone |
|
50 |
|
Vice President, Finance and Chief Accounting Officer |
|
Julian M. Bott |
|
51 |
|
Director |
|
Michael A. Bryson |
|
67 |
|
Director |
|
Lara E. Washington |
|
46 |
|
Director |
Mr. Porges was appointed as Chairman of the Board and as President and Chief Executive Officer of the Partnership’s general partner in January 2012. Mr. Porges is currently the Chairman, President and Chief Executive Officer of EQT and has held such positions since May 2011. Mr. Porges was President, Chief Executive Officer and Director of EQT from April 2010 through May 2011 and President, Chief Operating Officer and Director of EQT from February 2007 through April 2010. Mr. Porges has served as a member of EQT’s board since May 2002.
Mr. Porges brings extensive business, leadership, management and financial experience, as well as tremendous knowledge of the Partnership’s operations, culture and industry to the Board. Mr. Porges has served in a number of senior management positions with EQT since joining EQT as Senior Vice President and Chief Financial Officer in 1998. He has also served as a member of EQT’s board since May 2002. Prior to joining EQT, Mr. Porges held various senior positions within the investment banking industry and also held several managerial positions with Exxon Corporation (now, Exxon Mobil Corporation, an international oil and gas company). Mr. Porges served on the board of directors of Westport Resources Corp. (an oil and natural gas production company that is now part of Kerr-McGee Corp.) from April 2000 through 2004. Mr. Porges’ strong financial and industry experience, along with his understanding of the Partnership’s business operations and culture, enable Mr. Porges to provide unique and valuable perspectives on most issues facing the Partnership.
Mr. Conti was appointed as a director and as Senior Vice President and Chief Financial Officer of the Partnership’s general partner in January 2012. Mr. Conti is currently the Senior Vice President and Chief Financial Officer of EQT and has held such position since February 2007.
Mr. Conti brings significant energy industry management, finance and corporate development experience to the Board. Since joining EQT in 1996, Mr. Conti has served in a number of finance, business planning and business development senior management positions. From 1992 to 1996, Mr. Conti was vice president in the natural resources department at PNC Bank. Prior to that, he was a banking officer in the energy and utilities department of Mellon Bank, N.A., and before that, senior production engineer at Tenneco Oil Company. Given his experience as Senior Vice President and Chief Financial Officer of EQT, Mr. Conti has a thorough understanding of the Partnership’s capital structure and financing requirements, enabling him to provide leadership to the Board in these areas. Mr. Conti also brings valuable industry financial expertise from his prior role as an energy industry banker, including experience with capital markets transactions.
Mr. Crawford was appointed as a director of the Partnership’s general partner in January 2012. Mr. Crawford has served as Executive Vice President and Chief Operating Officer of the Partnership’s general partner since December 2013; and from January 2012 to December 2013, Mr. Crawford served as Executive Vice President. Mr. Crawford is currently the Senior Vice President and President, Midstream and Commercial of EQT and has held such position since December 2013. Mr. Crawford was Senior Vice President and President, Midstream, Commercial and Distribution from April 2010 to December 2013 and Senior Vice President and President, Midstream and Distribution from January 2008 to April 2010.
Mr. Crawford brings deep business, senior management and technical industry experience as well as in-depth knowledge of the Partnership’s business operations to the Board. Since 2007, Mr. Crawford has served as President of EQT’s midstream operations, including the Partnership’s operations. In this role, Mr. Crawford is responsible for executing the growth strategy for EQT’s natural gas midstream and production marketing companies operating in the rapidly growing Marcellus Shale natural gas supply region. Prior to joining EQT, Mr. Crawford held various financial and regulatory management positions with Consolidated Natural Gas Company (now part of Dominion Resources, Inc.) in Pittsburgh, and started his career with Price Waterhouse LLC Utility Services Practice. Mr. Crawford’s extensive understanding of the Partnership’s assets and operations enables him to bring valuable perspectives to the Board, particularly with respect to setting and implementing the Partnership’s business strategy.
Mr. Gardner was appointed as a director of the Partnership’s general partner in January 2012. Mr. Gardner is currently the General Counsel and Vice President, External Affairs of EQT and has held such position since April 2008. From January 2008 to March 2008, Mr. Gardner was Managing Director, External Affairs and Labor Relations of EQT.
In his current role with EQT, Mr. Gardner oversees legal and external affairs, which includes the safety and environmental, governmental relations and corporate communications functions. Prior to joining EQT in 2003, Mr. Gardner was a partner in the Houston and Austin, Texas offices of Brown, McCarroll & Oaks Hartline, general counsel to General Glass International Corp., a privately held glass manufacturing and trading company, and senior counsel, employment law with Northrop Grumman (formerly TRW, Inc.). Mr. Gardner’s experiences enable him to provide insight to the Board with respect to legal and external affairs issues, along with providing valuable perspectives with respect to business management and corporate governance issues.
Ms. Bone was appointed as Vice President, Finance and Chief Accounting Officer of the Partnership’s general partner in October 2013, and from January 2012 to October 2013, served as Vice President and Principal Accounting Officer. Ms. Bone is currently the Vice President, Finance and Chief Accounting Officer of EQT and has held such position since October 2013. From July 2007 to October 2013, Ms. Bone served as Vice President and Corporate Controller of EQT.
Mr. Bott was appointed as a director of the Partnership’s general partner in May 2012. Mr. Bott is currently the Chief Financial Officer of Texas American Resources Company, a privately held oil and gas acquisition, exploration and production company, and has held such position since December 2009. From December 2008 to November 2009, Mr. Bott served as an advisor to Kensington Energy Partners, which is a firm that advised energy companies and their stakeholders on financial and operational restructuring transactions. From January 2005 to December 2008, Mr. Bott was a principal and Chief Financial Officer of 3DMD Technologies LTD, a company specializing in 3D data capturing technology and related applications for the biometric and medical industries. Prior to that, Mr. Bott held various senior energy industry focused positions within the investment banking industry.
Mr. Bott has significant experience in energy company senior management, finance and corporate development. Mr. Bott is able to draw upon his diverse senior management and investment banking experience to provide guidance with respect to accounting matters, financial markets, financing transactions and energy company operations.
Mr. Bryson was appointed as a director of the Partnership’s general partner in May 2012. Mr. Bryson retired in June 2008 as Executive Vice President of The Bank of New York Mellon Corporation, a financial services firm. He obtained such position in July 2007 following the merger of Mellon Financial Corporation and The Bank of New York. Prior to the merger, Mr. Bryson served in various senior management positions over a 33-year career with Mellon Financial Corporation, including his service as Executive Vice President and Chief Financial Officer from December 2001 to June 2007.
Mr. Bryson brings to the Board over three decades of management and financial experience, having served as Treasurer and Chief Financial Officer of a large publicly traded financial institution. In these roles, Mr. Bryson obtained a wealth of experience related to financial statement preparation, auditing and accounting matters, financial markets, financing transactions and investor relations.
Ms. Washington was appointed as a director of the Partnership’s general partner in February 2013. Ms. Washington is currently President of the Allegheny County Rehabilitation Corporation (AHRCO), a privately held residential property management company serving Western Pennsylvania. She obtained such position in May 2008. Ms. Washington joined AHRCO in 2001 as Vice President of Development. Prior to joining AHRCO, Ms. Washington was a senior consultant with PricewaterhouseCoopers, LLP.
Ms. Washington’s service as President of a private company provides significant senior management, leadership and financial experience. Ms. Washington utilizes her broad business experience to provide valuable insights with respect to general business and management issues facing the Partnership.
Meetings of Non-Management Directors and Communications with Directors
At least annually, all of the independent directors of the Partnership’s general partner meet in executive session without management participation or participation by non-independent directors. Mr. Bryson, as the Chair of the audit committee, serves as the presiding director for such executive sessions. The presiding director may be contacted by mail or courier service c/o EQT Midstream Services, LLC, 625 Liberty Avenue, Suite 1700, Pittsburgh, Pennsylvania 15222, Attn: Presiding Director or by email at presidingdirector@eqtmidstreampartners.com.
Committees of the Board of Directors
The board of directors of the Partnership’s general partner has two standing committees: an audit committee and a conflicts committee. The NYSE does not require a publicly traded limited partnership like the Partnership to have a majority of independent directors on the board of directors of its general partner or to establish a compensation or a nominating and corporate governance committee.
Audit Committee
The Partnership’s general partner is required by the NYSE to have an audit committee of at least three members and all of the audit committee members must meet the independence and experience requirements established by the NYSE and the Exchange Act.
The audit committee consists of Messrs. Bryson (Chairman) and Bott and Ms. Washington. Each member of the audit committee satisfies the independence requirements established by the NYSE and the Exchange Act and is financially literate. Additionally, the board of directors of the Partnership’s general partner has determined that each member of the audit committee qualifies as an “audit committee financial expert” as such term is defined under the SEC’s regulations. This designation is a disclosure requirement of the SEC related to each audit committee members’ experience and understanding with respect to certain accounting and auditing matters. The designation does not impose upon the audit committee members any duties, obligations or liabilities that are greater than those generally imposed on them as members of the audit committee and the board of directors of the Partnership’s
general partner. As audit committee financial experts, each member of the audit committee also has the accounting or related financial management expertise required by the NYSE rules.
The audit committee assists the board of directors of the Partnership’s general partner in its oversight of the integrity of the Partnership’s financial statements and compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the sole authority to retain and terminate the Partnership’s independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by the Partnership’s independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of the Partnership’s independent registered public accounting firm.
Conflicts Committee
The conflicts committee consists of Messrs. Bott (Chairman) and Bryson and Ms. Washington. The conflicts committee, upon request by the Partnership’s general partner, determines whether certain transactions, which may be deemed conflicts of interest, are in the best interests of the Partnership. There is no requirement that the Partnership’s general partner seek the approval of the conflicts committee for the resolution of any conflict. The members of the conflicts committee may not be officers or employees of the Partnership’s general partner or directors, officers or employees of its affiliates, may not hold an ownership interest in the general partner or its affiliates other than common units or awards under any long-term incentive plan, equity compensation plan or similar plan implemented by the general partner or the Partnership, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Any matters approved by the conflicts committee in good faith will be deemed to be approved by all of the Partnership’s partners and not a breach by the Partnership’s general partner of any duties it may owe the Partnership or its unitholders. Any unitholder challenging any matter approved by the conflicts committee will have the burden of proving that the members of the conflicts committee did not subjectively believe that the matter was in the best interests of the Partnership. Moreover, any acts taken or omitted to be taken in reliance upon the advice or opinions of experts such as legal counsel, accountants, appraisers, management consultants and investment bankers, where the Partnership’s general partner (or any members of the board of directors of the Partnership’s general partner including any member of the conflicts committee) reasonably believes the advice or opinion to be within such person’s professional or expert competence, shall be conclusively presumed to have been done or omitted in good faith.
Governance Principles
The Partnership has adopted a code of business conduct and ethics that applies to all directors, officers, employees, and other personnel of the Partnership and its subsidiaries, as well as the Partnership’s suppliers, vendors, agents, contractors and consultants. The Partnership will disclose any future amendments to the code of business conduct and ethics that relate to executive officers of the Partnership’s general partner on the Partnership’s website, as well as any waivers of the code of business conduct and ethics that relate to executive officers of the Partnership’s general partner.
The Partnership maintains a corporate governance page on its website which includes key information about its corporate governance practices, including its corporate governance guidelines, code of business conduct and ethics and audit committee charter. The corporate governance page can be found at www.eqtmidstreampartners.com, by clicking on the “Investors” link on the main page and then “Governance.” The Partnership will provide a copy of its corporate governance guidelines, code of business conduct and ethics and/or audit committee charter upon request by a unitholder to the Corporate Secretary of the Partnership’s general partner by mail or courier service c/o EQT Midstream Services, LLC, 625 Liberty Avenue, Suite 1700, Pittsburgh, Pennsylvania 15222, Attn: Corporate Secretary.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires that the directors and executive officers of the Partnership’s general partner and all persons who beneficially own more than 10% of the Partnership’s common units file initial reports of ownership and reports of changes in ownership of the Partnership’s common units with the SEC. As a practical matter, the Partnership assists the directors and executive officers of the Partnership’s general partner by monitoring transactions and completing and filing Section 16 reports on their behalf.
Based solely upon the Partnership’s review of copies of filings or written representations from the reporting persons, the Partnership believes that all reports for the executive officers and directors of the Partnership’s general partner and persons who beneficially own more than 10% of the Partnership’s common units that were required to be filed under Section 16(a) of the Exchange Act in 2013 were filed on a timely basis.
Item 11. Executive Compensation
Executive Compensation
The Partnership does not directly employ any of the persons responsible for managing its business. The Partnership is managed and operated by the directors and officers of its general partner, EQT Midstream Services, LLC. EQT employs all of the individuals who service the Partnership, including the executive officers of the Partnership’s general partner, and these individuals devote such portion of their productive time to the Partnership’s business and affairs as is required to manage and conduct the Partnership’s operations. The Partnership reimburses EQT for all salaries and related benefits and expenses for the employees of EQT who provide services to the Partnership pursuant to an allocation agreed upon between EQT and the Partnership under the terms of the omnibus agreement. Please read Item 13, “Certain Relationships and Related Transactions, and Director Independence – Agreements with EQT – Omnibus Agreement.”
The Summary Compensation Table below reflects the total compensation of the principal executive officer and of the two other most highly compensated executive officers of the Partnership’s general partner who were serving as executive officers at the end of 2013 (the “named executive officers”) for services rendered to all EQT-related entities, including the Partnership, EQT Midstream Services, LLC and EQT for the fiscal years ending December 31, 2013 and 2012.
SUMMARY COMPENSATION TABLE
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|
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NON-EQUITY |
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|
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|
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|
|
|
|
|
STOCK |
|
OPTION |
|
INCENTIVE PLAN |
|
ALL OTHER |
|
|
|
|
NAME AND PRINCIPAL |
|
YEAR |
|
SALARY |
|
BONUS |
|
AWARDS |
|
AWARDS |
|
COMPENSATION |
|
COMPENSATION |
|
TOTAL |
|
|
POSITION |
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($) |
|
($) |
|
($) (1) |
|
($) (2) |
|
($) (3) |
|
($) (4) |
|
($) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David L. Porges |
|
2013 |
|
882,693 |
|
- |
|
2,649,147 |
|
1,544,928 |
|
2,500,000 |
|
345,305 |
|
7,922,073 |
|
|
Chairman, President |
|
2012 |
|
826,923 |
|
- |
|
4,176,362 |
|
1,395,502 |
|
1,996,000 |
|
314,893 |
|
8,709,680 |
|
|
and Chief Executive |
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|
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Officer |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Philip P. Conti |
|
2013 |
|
415,385 |
|
- |
|
900,531 |
|
525,008 |
|
950,000 |
|
157,523 |
|
2,948,447 |
|
|
Senior Vice President |
|
2012 |
|
400,001 |
|
- |
|
1,151,708 |
|
427,356 |
|
730,000 |
|
144,991 |
|
2,854,056 |
|
|
and Chief Financial |
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|
|
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|
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|
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Officer |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Randall L. Crawford |
|
2013 |
|
459,000 |
|
- |
|
1,263,199 |
|
737,352 |
|
1,100,000 |
|
171,235 |
|
3,730,786 |
|
|
Executive Vice |
|
2012 |
|
436,923 |
|
- |
|
1,707,462 |
|
590,912 |
|
820,000 |
|
161,055 |
|
3,716,352 |
|
|
President and Chief Operating Officer |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) This column reflects the aggregate grant date fair values determined in accordance with FASB ASC Topic 718 for performance units granted in the applicable year under the 2012 EPIP, EQM TR Program and the 2013 EPIP (each as defined and described under the caption “Narrative Disclosure to Summary Compensation Table” below), using the assumptions described below. Pursuant to SEC rules, the amounts shown in the Summary Compensation Table for awards subject to performance conditions are based on the probable outcome as of the date of grant and exclude the impact of estimated forfeitures.
The 2012 EPIP is a three-year program that provides EQT stock-based awards. Each named executive officer was granted an award under the 2012 EPIP on January 1, 2012. The performance period for the 2012 EPIP is January 1, 2012 through December 31, 2014. The grant date fair values of the awards were: $3,413,600 for Mr. Porges; $1,044,000 for Mr. Conti;
and $1,445,600 for Mr. Crawford. The grant date fair values were computed by multiplying the number of units awarded to each named executive officer (42,670 for Mr. Porges; 13,050 for Mr. Conti; and 18,070 for Mr. Crawford) by $80.00, the grant date fair value of each unit calculated using a Monte Carlo pricing model with the following assumptions: (i) risk-free rate of return: 0.36%; (ii) dividend yield: 5.97%; (iii) volatility: 37.26%; and (iv) term: three years. Assuming, instead, that the highest level of performance conditions would be achieved, the grant date fair values of these awards would have been: $5,834,696 for Mr. Porges; $1,784,457 for Mr. Conti; and $2,470,892 for Mr. Crawford.
The EQM TR Program is a three and one-half year program (subject to certain quarterly extensions as described under “Stock Awards – EQM TR Program” under the caption “Narrative Disclosure to Summary Compensation Table” below) that provides Partnership unit-based awards. Each named executive officer was granted an award on July 2, 2012. The performance period for the EQM TR Program is June 27, 2012 through December 31, 2015 (subject to quarterly extensions). The grant date fair values of the awards were: $762,762 for Mr. Porges; $107,708 for Mr. Conti; and $261,862 for Mr. Crawford. The grant date fair values were computed by multiplying the number of units awarded to each named executive officer (38,100 for Mr. Porges; 5,380 for Mr. Conti; and 13,080 for Mr. Crawford) by $20.02, the grant date fair value of each unit calculated using a Monte Carlo pricing model with the following assumptions: (i) risk-free rate of return for periods within the contractual life of the awards based on the applicable U.S. Treasury yield curves in effect at the time of the grant; (ii) an expected quarterly distribution of $0.35 per Partnership common unit for the first year and assuming annual increases of 10% per annum thereafter; (iii) the annual historical volatility of a peer group of companies for the expected term of the awards (the valuation model calculated a range of expected volatilities of 27% to 72% and a weighted average expected volatility of 38%); and (iv) a term of five years.
The 2013 EPIP is a three-year program that provides EQT stock-based awards. Each named executive officer was granted an award under the 2013 EPIP on January 1, 2013. The performance period for the 2013 EPIP is January 1, 2013 through December 31, 2015. The grant date fair values of the awards were: $2,649,147 for Mr. Porges; $900,531 for Mr. Conti; and $1,263,199 for Mr. Crawford. The grant date fair values were computed by multiplying the number of units awarded to each named executive officer (23,740 for Mr. Porges; 8,070 for Mr. Conti; and 11,320 for Mr. Crawford) by $111.59, the grant date fair value of each unit calculated using a Monte Carlo pricing model with the following assumptions: (i) risk-free rate of return: 0.36%; (ii) dividend yield: 0.72%; (iii) volatility: 32.97%; and (iv) term: three years. Assuming, instead, that the highest level of performance conditions would be achieved, the grant date fair values of these awards would have been: $3,323,600 for Mr. Porges; $1,129,800 for Mr. Conti; and $1,584,800 for Mr. Crawford.
See “Narrative Disclosure to Summary Compensation Table” below for a further discussion of the 2012 EPIP, the EQM TR Program and the 2013 EPIP.
(2) This column reflects the grant date fair values of EQT stock option awards issued on January 1, 2012 and January 1, 2013.
The grant date fair values of the 2012 EQT stock option awards were calculated by multiplying the number of options awarded to each named executive officer (105,800 for Mr. Porges; 32,400 for Mr. Conti; and 44,800 for Mr. Crawford) by $13.19, the grant date fair value of each option calculated using a Black-Scholes option pricing model with the following assumptions: (i) risk-free rate of return: 0.89%; (ii) dividend yield: 1.64%; (iii) volatility factor: 31.44%; and (iv) expected term: five years.
The grant date fair values of the 2013 EQT stock option awards were calculated by multiplying the number of options awarded to each named executive officer (92,400 for Mr. Porges; 31,400 for Mr. Conti; and 44,100 for Mr. Crawford) by $16.72, the grant date fair value of each option calculated using a Black-Scholes option pricing model with the following assumptions: (i) risk-free rate of return: 0.76%; (ii) dividend yield: 0.22%; (iii) volatility factor: 31.69%; and (iv) expected term: five years.
See “Option Awards – EQT 2012 Options” and “Option Awards – EQT 2013 Options” under the caption “Narrative Disclosure to Summary Compensation Table” below for further discussion of the EQT 2012 and 2013 options.
(3) This column reflects the dollar value of annual incentive compensation earned under the Executive STIP (as defined and described under the caption “Narrative Disclosure to Summary Compensation Table” below) during the applicable year. The awards were paid to the named executive officers in cash in the first quarter of the following year. For 2013, the Executive STIP awards for Messrs. Porges, Conti and Crawford included transaction recognition components for the completion of significant business transactions during 2013, in the following amounts: $200,000 for Mr. Porges; $100,000 for Mr. Conti; and $100,000 for Mr. Crawford. See “Non-Equity Incentive Plan Compensation – EQT Executive Short-Term Incentive Plan (Executive STIP) under the caption “Narrative Disclosure to Summary Compensation Table” below for further discussion of the Executive STIP for the 2013 plan year.
(4) This column includes the dollar value of premiums paid by EQT for group life, accidental death and dismemberment insurance, EQT’s contributions to the 401(k) plan and the 2006 Payroll Deduction and Contribution Program and perquisites. For 2013, these amounts were as follows:
|
|
|
INSURANCE |
|
401(K) |
|
2006 |
|
PERQUISITES |
|
TOTAL |
|
|
NAME |
|
($) |
|
($) |
|
($) |
|
($) |
|
($) |
|
|
David L. Porges |
|
2,448 |
|
22,950 |
|
276,052 |
|
43,855 |
|
345,305 |
|
|
Philip P. Conti |
|
1,152 |
|
22,950 |
|
94,735 |
|
38,686 |
|
157,523 |
|
|
Randall L. Crawford |
|
1,273 |
|
22,950 |
|
108,560 |
|
38,452 |
|
171,235 |
|
Once 401(k) contributions for the named executive officers reach the maximum level permitted under the 401(k) plan or by regulation, EQT contributions are continued on an after-tax basis under the 2006 Payroll Deduction and Contribution Program through an annuity program offered by Fidelity Investments Life Insurance Co. In 2013, EQT also contributed an amount equal to 11% of each named executive officer’s 2012 annual incentive award to such program.
The perquisites EQT provided to each named executive officer in 2013 are itemized below:
|
|
|
CAR |
|
COUNTRY AND |
|
FINANCIAL |
|
PARKING |
|
PHYSICAL |
|
TOTAL |
|
|
NAME |
|
($) |
|
($) |
|
($) |
|
($) |
|
($) |
|
($) |
|
|
David L. Porges |
|
9,533 |
|
14,344 |
|
15,000 |
|
1,978 |
|
3,000 |
|
43,855 |
|
|
Philip P. Conti |
|
9,408 |
|
8,800 |
|
14,150 |
|
1,978 |
|
4,350 |
|
38,686 |
|
|
Randall L. Crawford |
|
9,408 |
|
12,566 |
|
14,500 |
|
1,978 |
|
- |
|
38,452 |
|
The car allowance is an amount paid to the executive intended to cover the annual cost of acquiring, maintaining and insuring a car. The entire cost of country and dining club dues has been included in the table although EQT believes that only a portion of the cost represents a perquisite. Financial planning is the actual cost to EQT of providing to each executive financial planning and tax preparation services. The named executive officers may use two tickets purchased by EQT to attend up to four sporting or other events when such tickets are not otherwise being used for business purposes. The costs of such tickets used for personal purposes are considered de minimis by EQT and are not included as perquisites in the Summary Compensation Table because there are no incremental costs to EQT associated with such use. In 2013, none of the named executive officers used tickets purchased by EQT to attend sporting or other events in excess of the four event de minimis level.
NARRATIVE DISCLOSURE TO SUMMARY COMPENSATION TABLE
Set forth below is a discussion of the material elements of compensation paid to our named executive officers as reflected in the Summary Compensation Table. This discussion should be read in conjunction with the Summary Compensation Table above.
Base Salary
The base salary for each named executive officer reflected in the Summary Compensation Table above is the base salary actually earned and reflects a proportionate amount of any increase made during the applicable year.
Non-Equity Incentive Plan Compensation - EQT Executive Short-Term Incentive Plan (Executive STIP)
Before or at the start of each year, the Management Development and Compensation Committee of EQT (the “MDC Committee”) establishes the performance measure for determining awards under the Executive STIP. This performance measure establishes the maximum annual incentive award that the Committee may approve as “performance-based compensation” for tax purposes pursuant to Code Section 162(m) subject to the shareholder
approved individual limit set forth in the Executive STIP but does not set an expectation for the amount of annual incentive that will actually be paid. The MDC Committee is permitted to exercise, and has generally exercised, discretion downward in determining the actual payout under the annual incentive plan. The MDC Committee may not exercise upward discretion. The performance measure approved for the Executive STIP for the 2013 plan year was EQT’s 2013 EBITDA calculated using a fixed natural gas price of $3.75 per Mcfe, normalized for weather and excluding the effects of acquisitions and dispositions greater than $100 million (“adjusted 2013 EBITDA”), compared to EQT’s 2013 business plan as follows:
|
EQT ADJUSTED 2013 EBITDA |
|
PERCENTAGE OF EQT ADJUSTED |
|
At or above plan |
|
2% |
|
5% below plan |
|
1.5% |
|
25% below plan |
|
1% |
|
Greater than 25% below plan |
|
No bonus |
The percentage of EQT adjusted 2013 EBITDA available for all executive officer bonuses was interpolated between levels and capped at 2%. EQT’s actual adjusted 2013 EBITDA of $1,393 million exceeded plan by 10%, which allowed the MDC Committee to award annual incentives to EQT’s executive officers in an aggregate amount of $27.9 million, subject to a $5 million cap per executive officer. The MDC Committee exercised its discretion to pay each named executive officer a lesser amount based on the individual’s 2013 target award and 2013 performance on EQT, business unit and individual value drivers.
The Executive STIP provides that the annual awards will be paid in cash, subject to MDC Committee discretion to pay in equity. The MDC Committee typically considers settling awards in equity rather than cash only when an executive has not satisfied the applicable equity ownership guidelines.
Stock Awards – EQT 2012 Executive Performance Incentive Plan (2012 EPIP)
Awards under the 2012 EPIP were granted on January 1, 2012. Each named executive officer was granted an award under the 2012 EPIP.
The performance measures for the 2012 EPIP are:
• EQT’s total shareholder return (TSR) over the period January 1, 2012 through December 31, 2014, as ranked among the comparably measured TSR of the applicable peer group; and
• cumulative cash flow per share, which is the aggregate net cash provided by operating activities excluding changes in operating assets and liabilities during the performance period, adjusted to reflect a fixed natural gas price of $4.00 per Mcf, divided by the diluted common shares of EQT outstanding as of the end of each year in the performance period.
The payout opportunity under the 2012 EPIP ranges from:
• no payout if EQT is one of the nine lowest-ranking companies in the applicable peer group as to TSR and has cumulative cash flow per share over the performance period of less than $15.90;
• to target payout if EQT ranks seventeenth to fourteenth in the applicable peer group as to TSR and has cumulative cash flow per share over the performance period equal to $19.30;
• to three times the target award if EQT is one of the four highest-ranking companies in the applicable peer group as to TSR and has cumulative cash flow per share over the performance period of at least $27.49.
If earned, the EQT share units are expected to be distributed in shares of EQT common stock equal to the target award (including accrued dividends) multiplied by the applicable payout multiple.
Stock Awards – EQT Midstream Partners, LP Total Return Program (EQM TR Program)
Performance awards under the EQM TR Program, a program adopted under EQT’s 2009 Long-Term Incentive Plan and the EQT Midstream Services, LLC 2012 Long-Term Incentive Plan, were granted on July 2, 2012. Each named executive officer was awarded performance units under the EQM TR Program.
The performance measure for the program is total Partnership unitholder return of at least 10%, measured from June 27, 2012, the date of the Partnership’s initial public offering, through December 31, 2015. If the unitholder return measure is not achieved as of December 31, 2015, the performance condition will nonetheless be satisfied if the 10% unitholder return threshold is satisfied as of the end of any calendar quarter ending after December 31, 2015 and on or before December 31, 2017.
The payout opportunity under the EQM TR Program is:
• no payout if the total Partnership unitholder return is less than 10% over the performance period; or
• target payout if the total unitholder return equals or exceeds 10% over the performance period.
If earned, the performance awards are expected to be distributed in Partnership common units equal to the target award (including accrued distributions).
Stock Awards – EQT 2013 Executive Performance Incentive Plan (2013 EPIP)
Awards under the 2013 EPIP were granted on January 1, 2013. The performance measures for the 2013 EPIP are:
• EQT’s TSR over the period January 1, 2013 through December 31, 2015, as ranked among the comparably measured TSR of the applicable peer group; and
• cumulative cash flow per share, which is the aggregate net cash provided by operating activities excluding changes in other assets and liabilities during the performance period, adjusted to reflect a fixed natural gas price of $2.79 per Mcf, divided by the diluted common shares outstanding as of the end of each year in the performance period.
The payout opportunity under the 2013 EPIP ranges from:
• no payout if EQT is one of the nine lowest-ranking companies in the applicable peer group as to TSR and has cumulative cash flow per share over the performance period of less than $16.59;
• to target payout if EQT ranks seventeenth to fourteenth in the applicable peer group as to TSR and has cumulative cash flow per share over the performance period equal to $18.30;
• to three times the target award if EQT is one of the four highest-ranking companies in the applicable peer group as to TSR and has cumulative cash flow per share over the performance period of at least $24.15.
If earned, the share units are expected to be distributed in shares of common stock equal to the target award (including accrued dividends) multiplied by the applicable payout multiple.
See Item 12, “Securities Authorized for Issuance under Equity Compensation Plans” below for a discussion of the EQT Midstream Services, LLC 2012 Long-Term Incentive Plan.
Option Awards – EQT 2012 Options
The 2012 options for EQT common stock were awarded on January 1, 2012 with an exercise price of $54.79. The options are ten-year options and vested as follows: 50% vested on January 1, 2013 and 50% vested on January 1, 2014.
Option Awards – EQT 2013 Options
The 2013 options for EQT common stock were awarded on January 1, 2013 with an exercise price of $58.98. The options are ten-year options and vest as follows: 50% vested on January 1, 2014 and 50% will vest on January 1, 2015, contingent upon continued employment with EQT on such date.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
The following table reflects all outstanding equity awards as of December 31, 2013, including equity awards of both EQT and the Partnership.
|
OPTION AWARDS |
|
EQUITY AWARDS |
| ||||||||||||||
|
|
|
|
|
|
| ||||||||||||
|
|
|
NUMBER OF |
|
NUMBER OF |
|
OPTION |
|
OPTION |
|
NUMBER OF |
|
MARKET |
|
EQUITY |
|
EQUITY |
|
|
|
|
(#) |
|
(#) (1) |
|
($) |
|
|
|
(#) |
|
($) |
|
(#) (2) |
|
($) (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David L. Porges |
|
109,200 |
|
- |
|
48.91 |
|
8/5/2015 |
|
- |
|
- |
|
103,566 |
|
9,298,155 |
|
|
|
|
57,200 |
|
- |
|
43.92 |
|
1/1/2017 |
|
- |
|
- |
|
130,356 |
|
11,703,362 |
|
|
|
|
76,800 |
|
- |
|
38.53 |
|
8/2/2017 |
|
- |
|
- |
|
39,875 |
|
2,344,251 |
|
|
|
|
76,700 |
|
- |
|
44.84 |
|
1/1/2018 |
|
- |
|
- |
|
71,331 |
|
6,404,097 |
|
|
|
|
52,900 |
|
- |
|
54.79 |
|
1/1/2022 |
|
- |
|
- |
|
- |
|
- |
|
|
|
|
- |
|
52,900 |
|
54.79 |
|
1/1/2022 |
|
- |
|
- |
|
- |
|
- |
|
|
|
|
- |
|
92,400 |
|
58.98 |
|
1/1/2023 |
|
- |
|
- |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Philip P. Conti |
|
28,300 |
|
- |
|
44.84 |
|
1/1/2018 |
|
- |
|
- |
|
38,196 |
|
3,429,237 |
|
|
|
|
16,200 |
|
- |
|
54.79 |
|
1/1/2022 |
|
- |
|
- |
|
39,867 |
|
3,579,259 |
|
|
|
|
- |
|
16,200 |
|
54.79 |
|
1/1/2022 |
|
- |
|
- |
|
5,631 |
|
331,046 |
|
|
|
|
- |
|
31,400 |
|
58.98 |
|
1/1/2023 |
|
- |
|
- |
|
24,249 |
|
2,177,075 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Randall L. Crawford |
|
87,000 |
|
- |
|
48.91 |
|
8/5/2015 |
|
- |
|
- |
|
51,963 |
|
4,665,238 |
|
|
|
|
21,400 |
|
- |
|
43.92 |
|
1/1/2017 |
|
- |
|
- |
|
55,203 |
|
4,956,125 |
|
|
|
|
38,500 |
|
- |
|
44.84 |
|
1/1/2018 |
|
- |
|
- |
|
13,690 |
|
804,835 |
|
|
|
|
22,400 |
|
- |
|
54.79 |
|
1/1/2022 |
|
- |
|
- |
|
34,014 |
|
3,053,777 |
|
|
|
|
- |
|
22,400 |
|
54.79 |
|
1/1/2022 |
|
- |
|
- |
|
- |
|
- |
|
|
|
|
- |
|
44,100 |
|
58.98 |
|
1/1/2023 |
|
- |
|
- |
|
- |
|
- |
|
(1) The options reflected in this column are EQT options which vest according to the following schedule: of the options expiring in 2022, 100% were vested as of January 1, 2014 and of the options expiring in 2023, 50% vested on January 1, 2014 and 50% will vest on January 1, 2015.
(2) This column reflects performance units awarded but that had not vested at December 31, 2013 pursuant to the EQT 2011 Volume and Efficiency Program (2011 VEP), the 2012 EPIP, the EQM TR Program and the 2013 EPIP (including accrued dividends for the 2011 VEP, 2012 EPIP and the 2013 EPIP and accrued distributions for the EQM TR Program). The number of performance units under the 2011 VEP, the 2012 EPIP and the 2013 EPIP reflects maximum award levels because, through December 31, 2013, payout was projected above the target level for each program. The number of performance units under the EQM TR Program reflects target award levels because, through December 31, 2013, total EQM
unitholder return was projected to exceed 10% at the end of the performance period and there is no award level above target for this program. Awards under the 2012 EPIP, the EQM TR Program and the 2013 EPIP do not vest until payment following the end of the respective performance periods.
(3) This column reflects the payout values at December 31, 2013 of unearned performance units granted under the 2011 VEP, the 2012 EPIP, the EQM TR Program and the 2013 EPIP (including accrued dividends for the 2011 VEP, the 2012 EPIP and the 2013 EPIP and accrued distributions for the EQM TR Program). The payout values are determined by multiplying the number of units as shown in the previous column by $89.78, the closing price of EQT’s common stock on December 31, 2013 (or, for the EQM TR Program, by $58.79, the closing price of the Partnership’s common units on December 31, 2013). The actual payout values under the 2012 EPIP and the 2013 EPIP will depend upon, among other things, EQT’s actual performance through, and the stock price at the end of, the applicable performance periods. The actual payout values under the EQM TR Program will depend upon, among other things, the Partnership’s actual performance through, and the Partnership’s common unit price at the end of, the program’s performance period.
Retirement Benefits
The executive officers of the Partnership’s general partner participate in employee benefit plans and arrangements sponsored by EQT. Neither the Partnership nor its general partner currently offers any deferred compensation program or any supplemental executive retirement plan to any of the executive officers of the Partnership’s general partner. EQT provides full discussion of its plans and arrangements in its filings with the SEC, including its annual proxy statement relating to the annual meeting of the shareholders of EQT, which filings are available on the SEC’s website at www.sec.gov and on EQT’s website at www.EQT.com on the “SEC Filings” page under the “Investors Relations” tab. The secretary of our general partner will also provide a copy to you free of charge upon request.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL
EQT Midstream Services, LLC 2012 Long-Term Incentive Plan
The EQT Midstream Services, LLC 2012 Long-Term Incentive Plan provides for certain rights upon the occurrence of a change of control, as defined in the plan. Unless an award agreement otherwise provides or the plan administrator otherwise determines at the time of grant, in the event that a change of control occurs (1) all outstanding options, unit appreciation rights and other exercise rights will become immediately and fully exercisable, and (2) all restrictions, excluding performance-based restrictions, applicable to awards under the plan will lapse, and (3) all performance criteria and other conditions to payment of awards under which payments are subject to performance conditions shall be deemed to be achieved or fulfilled, measured at the actual performance level achieved as of the end of the calendar quarter immediately preceding the date of the change of control, and payment of such awards on that basis shall be made or otherwise settled at the time of the change of control, provided that if the awards constitute deferred compensation the awards shall vest on the basis described above and shall remain payable on the dates provided in the underlying award agreements.
If within three years following the date of any change of control the employment or service of a participant is terminated voluntarily or involuntarily for any reason other than for “cause”, as defined in the plan, then unless otherwise provided in the applicable award agreement, any option, unit appreciation right or other purchase right shall be exercisable for a period of 90 days following the date of such termination of employment or service but not later than the expiration date of the award.
EQM TR Program
Under the EQM TR Program, if a participant’s employment terminates for any reason, including retirement, at any time prior to the applicable vesting date, the participant’s awarded units are forfeited, except under the following circumstances:
• If the participant’s employment is terminated voluntarily or involuntarily without fault on the participant’s part (including retirement) and the participant remains on the Board of Directors of EQT or the Board of Directors of EQT Midstream Services, LLC, the general partner of the Partnership, following termination, then the participant’s performance awards continue to vest for so long as the participant remains on such Board; and
• If a participant’s employment is otherwise terminated involuntarily and without fault (including a termination resulting from death or disability) prior to payment, the participant may receive payment for a percentage of the participant’s performance units following termination of the performance period, contingent upon achievement of the performance condition, as follows:
|
TERMINATION DATE |
|
AWARDED UNITS |
|
|
Prior to January 1, 2014 |
|
0% |
|
|
January 1, 2014 – December 31, 2014 |
|
25% |
|
|
January 1, 2015 and thereafter |
|
50% |
|
EQT Plans and Agreements
EQT maintains and has entered into certain plans and agreements (including those described above in “Narrative Disclosure to Summary Compensation Table”) that require EQT to provide compensation to the named executive officers, among others, in the event of a termination of employment or a change of control of EQT. EQT provides full discussion of these plans and agreements in its filings with the SEC, including its annual proxy statement relating to the annual meeting of the shareholders of EQT, which filings are available on the SEC’s website at www.sec.gov and on EQT’s website at www.EQT.com on the “SEC Filings” page under the “Investors Relations” tab. The secretary of our general partner will also provide a copy to you free of charge upon request.
Compensation of Directors
Officers or employees of EQT or its affiliates who also serve as directors of EQT Midstream Services, LLC, the Partnership’s general partner, do not receive additional compensation for their service as directors. Directors of the Partnership’s general partner who are not also officers or employees of EQT or its affiliates receive cash compensation on a quarterly basis as a retainer and for attending meetings of the board of directors and committee meetings as follows:
• An annual cash retainer of $40,000.
• A cash meeting fee of $1,500 for each board and committee meeting attended in person. If a director participates in a meeting by telephone, the meeting fee is $750.
• For the audit committee chair and the conflicts committee chair, an annual committee chair retainer of $15,000.
In addition, each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings. The Partnership also provides non-employee directors with $20,000 of life insurance and $250,000 of travel accident insurance while traveling on business for the Partnership. To further the Partnership’s support for charitable giving, all directors are eligible to participate in the Matching Gifts Program of the EQT Foundation on the same terms as EQT employees and directors. Under this program, the EQT Foundation will match gifts of at least $100 made by the director to eligible charities, up to an aggregate total of $25,000 in any calendar year.
On an annual basis, the Partnership’s general partner grants to each non-employee director phantom units as a vehicle to deliver compensation for their annual service on the Board. On February 19, 2013, the Partnership’s general partner granted to each non-employee director who was a member of the Board at that time phantom units with a value of $50,000 under the 2012 Long-Term Incentive Plan (with the number of phantom units (1,330) determined by dividing the award value by the closing price of the Partnership’s common units on February 15, 2013 ($37.85) and rounding up to the next ten units). Ms. Washington, who was elected to the board of the Partnership’s general partner on February 22, 2013, received an award of 1,130 phantom units on February 22, 2013, which represented her pro-rata amount of the 2013 annual grant. The phantom units were fully vested as of the grant date, with distribution equivalents accruing on such units. The phantom units (and the accrued distribution equivalents) will be converted into common units on the date that the grantee ceases to be a director.
The table below shows the total 2013 compensation of the Partnership’s non-employee directors:
|
NAME |
|
FEES |
|
STOCK |
|
ALL OTHER |
|
TOTAL |
|
|
|
|
|
|
|
|
|
|
|
Michael A. Bryson |
|
79,000 |
|
50,340 |
|
24,488 |
|
153,828 |
|
Julian M. Bott |
|
77,500 |
|
50,340 |
|
55 |
|
127,895 |
|
Lara E. Washington |
|
52,222 |
|
43,019 |
|
3,555 |
|
98,796 |
(1) Includes cash retainer, meeting fees and committee chair fees.
(2) This column reflects the aggregate grant date fair values determined in accordance with FASB ASC Topic 718 for the phantom units awarded to each director during 2013. On February 19, 2013, the Partnership’s general partner granted 1,330 phantom units to each non-employee director who was a member of the board of the Partnership’s general partner at the time of grant. Ms. Washington, who was elected to the board of the Partnership’s general partner on February 22, 2013, received an award of 1,130 phantom units on February 22, 2013. The grant date fair value is computed as the sum of the number of phantom units awarded on the grant date multiplied by the closing price of the Partnership’s common units on the business day prior to the grant, which closing price was $37.85 on February 15, 2013 and $38.07 on February 21, 2013.
(3) This column reflects (i) annual premiums of $55.27 per director paid for life insurance and travel accident insurance policies and (ii) the following matching gifts made to qualifying organizations under the EQT Foundation’s Matching Gifts Program: Mr. Bryson - $24,433; and Ms. Washington - $3,500. The non-employee directors may use a de minimis number of tickets purchased by EQT to attend sporting or other events when such tickets are not otherwise being used for business purposes. The use of such tickets do not result in any incremental costs to the Partnership.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Security Ownership of Certain Beneficial Owners and Management
The following table sets forth the beneficial ownership of the Partnership’s units owned as of January 31, 2014, by:
• each of the directors of the Partnership’s general partner;
• each of the named executive officers of the Partnership’s general partner; and
• all directors and executive officers of the Partnership’s general partner as a group.
The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable, and none of the units are subject to a pledge.
Percentage of total units beneficially owned is based on 30,468,902 common units and 17,339,718 subordinated units outstanding as of January 31, 2014.
|
NAME OF BENEFICIAL OWNER(1) |
|
COMMON |
|
PERCENTAGE |
|
SUBORDINATED |
|
PERCENTAGE |
|
PERCENTAGE |
|
|
David L. Porges |
|
20,000 |
|
* |
|
— |
|
* |
|
* |
|
|
Philip P. Conti |
|
9,750 |
|
* |
|
— |
|
* |
|
* |
|
|
Randall L. Crawford |
|
25,000 |
|
* |
|
— |
|
* |
|
* |
|
|
Lewis B. Gardner |
|
9,500 |
|
* |
|
— |
|
* |
|
* |
|
|
Julian M. Bott |
|
6,724 |
|
* |
|
— |
|
* |
|
* |
|
|
Michael A. Bryson |
|
7,724 |
|
* |
|
— |
|
* |
|
* |
|
|
Lara E. Washington |
|
2,018 |
|
* |
|
— |
|
* |
|
* |
|
|
All directors and executive officers as a group (8 individuals) |
|
90,716 |
|
* |
|
— |
|
* |
|
* |
|
* Less than 1%.
(1) Unless otherwise indicated, the address for all beneficial owners in this table is c/o EQT Midstream Partners, LP, 625 Liberty Avenue, Pittsburgh, PA 15222, Attn: Corporate Secretary.
(2) This column reflects the number of common units held of record or owned through a bank, broker or other nominee. For Messrs. Bott and Bryson and Ms. Washington, it includes phantom units, including accrued distributions, to be settled in common units, in the following amounts; Mr. Bott – 4,724 units; Mr. Bryson – 4,724 units; and Ms. Washington – 2,018 units.
The following table sets forth the beneficial ownership of each person known by the Partnership to be a beneficial owner of more than 5% of the outstanding units of the Partnership:
|
NAME OF BENEFICIAL OWNER |
|
COMMON |
|
PERCENTAGE |
|
SUBORDINATED |
|
PERCENTAGE |
|
PERCENTAGE |
|
|
EQT Corporation(1) |
|
3,443,902 |
|
11.3% |
|
17,339,718 |
|
100% |
|
43.5% |
|
|
625 Liberty Avenue |
|
|
|
|
|
|
|
|
|
|
|
|
Pittsburgh, PA 15222 |
|
|
|
|
|
|
|
|
|
|
|
|
Goldman Sachs Asset Management Group, L.P. (2) |
|
2,554,196 |
|
8.4% |
|
— |
|
— |
|
— |
|
|
200 West Street |
|
|
|
|
|
|
|
|
|
|
|
|
New York, NY 10282 |
|
|
|
|
|
|
|
|
|
|
|
|
Tortoise Capital Advisors, LLC(3) |
|
2,321,123 |
|
7.6% |
|
— |
|
— |
|
— |
|
|
11550 Ash Street, Suite 300 |
|
|
|
|
|
|
|
|
|
|
|
|
Leawood, KS 66211 |
|
|
|
|
|
|
|
|
|
|
|
|
Oppenheimer Funds, Inc.(4) |
|
1,990,522 |
|
6.53% |
|
— |
|
— |
|
— |
|
|
Two World Financial Center |
|
|
|
|
|
|
|
|
|
|
|
|
New York, NY 10281 |
|
|
|
|
|
|
|
|
|
|
|
(1) EQT Corporation is the ultimate parent company of EQT Gathering, LLC, which is the sole owner of all of the membership interests of the Partnership’s general partner, which is the sole owner of the Partnership’s general partner units. EQT Gathering, LLC is also the sole owner of EQT Midstream Investments, LLC, which is the sole owner of 3,443,902 common units and 17,339,718 subordinated units. EQT may, therefore, be deemed to beneficially own the units held by EQT Gathering, LLC.
(2) Information based on a SEC Schedule 13G filed on February 13, 2014, reporting that Goldman Sachs Asset Management Group, L.P. has shared voting and dispositive power over 2,554,196 units.
(3) Information based on a SEC Schedule 13G filed on February 11, 2014, reporting that Tortoise Capital Advisors, LLC has shared voting power over 2,150,775 units and shared dispositive power over 2,321,123 units.
(4) Information based on a SEC Schedule 13G filed on February 6, 2014, reporting that Oppenheimer Funds, Inc. has shared voting and dispositive power over 1,990,552 units.
The following table sets forth, as of January 31, 2014, the number of shares of common stock of EQT Corporation owned by each of the named executive officers and directors of the Partnership’s general partner and all directors and executive officers of the Partnership’s general partner as a group.
|
Name |
|
Exercisable |
|
Number of Shares |
|
Percent of |
|
|
David L. Porges (4) |
|
471,900 |
|
522,291 |
|
* |
|
|
Philip P. Conti |
|
76,400 |
|
93,048 |
|
* |
|
|
Randall L. Crawford |
|
213,750 |
|
63,375 |
|
* |
|
|
Lewis B. Gardner |
|
47,400 |
|
19,503 |
|
* |
|
|
Julian M. Bott |
|
— |
|
— |
|
— |
|
|
Michael A. Bryson |
|
— |
|
— |
|
— |
|
|
Lara E. Washington |
|
— |
|
— |
|
— |
|
|
Directors and executive officers as a group (8 individuals) |
|
830,950 |
|
734,971 |
|
* |
|
* Less than 1%.
(1) This column reflects the number of shares of EQT Corporation common stock that the officers and directors of the Partnership’s general partner had a right to acquire within 60 days after January 31, 2014 through the exercise of stock options.
(2) This column reflects shares held of record and shares owned through a bank, broker or other nominee, including, for executive officers, shares owned through EQT Corporation’s 401(k) plan and unvested restricted shares owned through EQT’s long-term incentive plan (over which the executive officers have sole voting but no investment power).
(3) This column reflects for the executive officers and directors as a group (i) the sum of the shares beneficially owned and the stock options exercisable by the executive officers and director group within 60 days of January 31, 2014, as a percentage of (ii) the sum of EQT Corporation’s outstanding shares at January 31, 2014, and all options exercisable within 60 days of January 31, 2014.
(4) Shares beneficially owned include 50,000 shares that are held in a trust of which Mr. Porges is a co-trustee and in which he shares voting and investment power.
Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information as of December 31, 2013 with respect to the Partnership’s common units that may be issued under the 2012 Long-Term Incentive Plan, which did not require approval by the Partnership’s unitholders.
|
PLAN CATEGORY |
|
NUMBER OF |
|
WEIGHTED |
|
NUMBER OF |
|
|
|
|
(A) |
|
(B) |
|
(C) |
|
|
Equity Compensation Plans Approved by Unitholders |
|
— |
|
— |
|
— |
|
|
|
|
|
|
|
|
|
|
|
Equity Compensation Plans Not Approved by Unitholders(1) |
|
158,026 |
|
N/A |
|
1,683,948 |
|
|
Total |
|
158,026 |
|
N/A |
|
1,683,948 |
|
(1) The board of directors of the Partnership’s general partner adopted the 2012 Long-Term Incentive Plan in connection with the IPO of the Partnership’s common units.
EQT Midstream Services, LLC 2012 Long-Term Incentive Plan
The Partnership’s general partner adopted the EQT Midstream Services, LLC 2012 Long-Term Incentive Plan for employees and non-employee directors of the Partnership’s general partner and any of its affiliates. The Partnership’s general partner may issue long-term equity based awards under the plan. The Partnership is responsible for the cost of awards granted under the plan. Employees and non-employee directors of the Partnership’s general partner or any affiliate, including subsidiaries, are eligible to receive awards under the plan.
The aggregate number of units that may be issued under the plan is 2,000,000 units, subject to proportionate adjustment in the event of unit splits and similar events. Units underlying options and unit appreciation rights will count as one unit, and units underlying all other unit-based awards will count as two units, against the number of units available for issuance under the plan. Units subject to awards that terminate or expire unexercised, or are cancelled, forfeited or lapse for any reason, and units underlying awards that are ultimately settled in cash, will again become available for future grants of awards under the plan. Units delivered by the participant or withheld from an award to satisfy tax withholding requirements, and units delivered or withheld to pay the exercise price of an option, will not be used to replenish the plan unit reserve.
The plan is administered by the board of directors of the Partnership’s general partner or such other committee of the board as may be designated by the board to administer the plan.
The plan authorizes the granting of awards in any of the following forms: phantom units, performance awards, restricted units, distribution equivalent rights, market-priced options to purchase units, unit appreciation rights, other unit-based awards that are denominated or payable in, valued in whole or in part by reference to, or otherwise based on units, and cash-based awards.
The board of directors of the Partnership’s general partner may amend, suspend or terminate the plan at any time, except that no amendment may be made without the approval of the Partnership’s unitholders if unitholder
approval is required by any federal or state law or regulation or by the rules of any exchange on which the units may then be listed, or if the amendment, alteration or other change materially increases the benefits accruing to participants, increases the number of units available under the plan or modifies the requirements for participation under the plan, or if the Board in its discretion determines that obtaining such unitholder approval is for any reason advisable.
Common units to be delivered pursuant to awards under the plan may be common units acquired by the Partnership’s general partner in the open market, from any other person, directly from the Partnership or any combination of the foregoing. If the Partnership issues new common units upon the grant, vesting or payment of awards under the plan, the total number of common units outstanding will increase.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Certain Relationships and Related Transactions
As of January 31, 2014, EQT indirectly owned 3,443,902 common units and 17,339,718 subordinated units representing a 43.5% limited partner interest in the Partnership. In addition, the Partnership’s general partner owned a 2.0% general partner interest in the Partnership and the incentive distribution rights.
Distributions and Payments to the Partnership’s General Partner and Its Affiliates
The following information summarizes the distributions and payments made or to be made by the Partnership to the Partnership’s general partner and its affiliates in connection with the Partnership’s formation, ongoing operation and any liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Formation Stage
The aggregate consideration received by the Partnership’s general partner and its affiliates for the contribution of certain assets and liabilities to the Partnership in connection with the IPO:
• 2,964,718 common units
• 17,339,718 subordinated units
• 707,744 general partner units representing a 2.0% general partner interest;
• all of the incentive distribution rights; and
• a cash payment of approximately $231 million from the proceeds of the IPO.
Operational Stage
Distributions of available cash to the Partnership’s general partner and its affiliates. Unless distributions exceed the minimum quarterly distribution, the Partnership makes cash distributions 98.0% to the Partnership’s unitholders pro rata, including the Partnership’s general partner and its affiliates as holders of an aggregate of 3,443,902 common units and all of the subordinated units, and 2.0% to the Partnership’s general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, the Partnership’s general partner, by virtue of its incentive distribution rights, is entitled to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target level.
Payments to the Partnership’s general partner and its affiliates. The Partnership’s general partner does not receive a management fee or other compensation for managing the Partnership. The Partnership’s general partner and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on the Partnership’s behalf. The Partnership’s general partner determines the amount of these expenses. In addition, the Partnership reimburses EQT and its affiliates for the payment of certain operating expenses and for the provision of various general and administrative services for the Partnership’s benefit.
Withdrawal or removal of the Partnership’s general partner. If the Partnership’s general partner withdraws or is removed, its general partner interest and its incentive distribution rights 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 the Partnership’s liquidation, the partners, including the Partnership’s general partner, will be entitled to receive liquidating distributions according to their capital account balances.
Agreements with EQT
The Partnership and its affiliates have entered into various agreements with EQT and its affiliates other than the Partnership, as described in detail below. These agreements were negotiated in connection with the formation of the Partnership and the IPO and address, among other things, the acquisition of assets and the assumption of liabilities by the Partnership and its subsidiaries. These agreements were not the result of arm’s length negotiations and, as such, they or underlying transactions may not be based on terms as favorable as those that could have been obtained from unaffiliated third parties.
Omnibus Agreement
The Partnership and its general partner have entered into an omnibus agreement with EQT that governs the Partnership’s relationship with EQT regarding the following matters:
• the Partnership’s obligation to reimburse EQT and its affiliates for certain direct operating expenses they pay on the Partnership’s behalf (the “direct operating expenses”);
• the Partnership’s obligation to reimburse EQT and its affiliates for providing the Partnership corporate, general and administrative services (the “general and administrative expenses”);
• the Partnership’s obligation to reimburse EQT and its affiliates for operation and management services pursuant to the operation and management services agreement (the “operation and management expenses”);
• EQT’s obligation to indemnify or reimburse the Partnership for losses or expenses relating to or arising from (i) certain plugging and abandonment obligations; (ii) certain bare steel replacement capital expenditures; (iii) certain pipeline safety costs; (iv) certain preclosing environmental liabilities; (v) certain title and rights-of-way matters; (vi) the Partnership’s failure to have certain necessary governmental consents and permits; (vii) certain preclosing tax liabilities; (viii) assets previously owned by the Partnership and retained by EQT and its affiliates, including the Sunrise Pipeline; (ix) any claims related to Equitrans’ previous ownership of the Big Sandy Pipeline; and (x) any amounts owed to the Partnership by a third party that has exercised a contractual right of offset against amounts owed by EQT to such third party;
• the Partnership’s obligation to indemnify EQT for losses attributable to (i) the ownership or operation of the Partnership’s assets after the closing of the IPO, except to the extent EQT is obligated to indemnify the Partnership for such losses pursuant to the Operation and Management Services Agreement with EQT, as described below under “—Operation and Management Services Agreement;” and (ii) any amounts owed to EQT by a third party that has exercised a contractual right of offset against amounts owed by the Partnership to such third party; and
• the Partnership’s use of the name “EQT” and related marks.
Reimbursement of Expenses
Under the omnibus agreement, EQT performs, or causes its affiliates to perform, centralized corporate, general and administrative services for the Partnership, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. In exchange, the Partnership reimburses EQT and its affiliates for the expenses incurred by them in providing these services, except for any expenses associated with EQT’s long-term incentive programs. The omnibus agreement further provides that the Partnership
reimburse EQT and its affiliates for the Partnership’s allocable portion of the premiums on any insurance policies covering the Partnership’s assets.
The Partnership is required to reimburse EQT for any additional state income, franchise or similar tax paid by EQT resulting from the inclusion of the Partnership (and its subsidiaries) in a combined state income, franchise or similar tax report with EQT as required by applicable law. The amount of any such reimbursement is limited to the tax that the Partnership (and its subsidiaries) would have paid had they not been included in a combined group with EQT.
The table below sets forth the amounts and categories of expenses described above for which the Partnership was obligated to reimburse EQT pursuant to the omnibus agreement for the year ended December 31, 2013.
|
DESCRIPTION OF EXPENSES |
|
EXPENSE (IN MILLIONS) |
|
|
|
|
|
|
|
Reimbursement of general and administrative expenses |
|
$ 18.3 |
|
|
Reimbursement of operation and management expenses |
|
$ 14.3 |
|
Indemnification
EQT’s indemnification obligations to the Partnership include the following:
• Plugging and abandonment liabilities. For a period of ten years after the closing of the IPO, EQT is required to reimburse the Partnership for plugging and abandonment expenditures and other expenditures for certain identified wells of EQT and third parties. The reimbursement obligation of EQT with respect to wells owned by third parties is capped at $1.2 million per year.
• Bare steel replacement. EQT has agreed to reimburse the Partnership for bare steel replacement capital expenditures in the event that ongoing maintenance capital expenditures (other than capital expenditures associated with plugging and abandonment liabilities to be reimbursed by EQT) exceed $17.2 million (with respect to the Partnership’s assets at the time of the IPO) in any year. If such ongoing maintenance capital expenditures and bare steel replacement capital expenditures exceed $17.2 million during a year, EQT is required to reimburse the Partnership for the lesser of (i) the amount of bare steel replacement capital expenditures during such year and (ii) the amount by which such ongoing capital expenditures and bare steel replacement capital expenditures exceeds $17.2 million. This bare steel replacement reimbursement obligation is capped at an aggregate amount of $31.5 million over the ten years following the IPO.
• Pipeline Safety Cost Tracker Reimbursement. For a period of five years after the closing of the IPO, EQT is required to reimburse the Partnership for the amount by which the qualifying pipeline safety costs included in the annual pipeline safety cost tracker filings made by Equitrans with the FERC exceed the qualifying pipeline safety costs actually recovered each year.
• Environmental. For a period of three years after the closing of the IPO, EQT is required to indemnify the Partnership for certain potential environmental and toxic tort claims, losses and expenses associated with the operation of the assets retained by the Partnership and occurring before the closing date of the IPO. The maximum liability of EQT for these indemnification obligations is capped at $15 million and EQT will not have any obligation under these indemnification obligations until the Partnership’s aggregate losses exceed $250,000, after which EQT shall be liable for the full amount of such claims in excess of $250,000. EQT has no indemnification obligations with respect to environmental or toxic tort claims made as a result of additions to, or modifications of, environmental laws promulgated after the closing of the IPO.
• Title. For a period of three years after the closing of the IPO, EQT is required to indemnify the Partnership for losses relating to the Partnership’s failure to have valid and indefeasible easement rights, rights-of-way, leasehold and/or fee ownership interests in and to the lands on which the Partnership’s assets are located, and such failure prevents the Partnership from using or operating its assets in substantially the same manner that such assets were used and operated immediately prior to the closing of the IPO.
• Governmental consents and permits. For a period of three years after the closing of the IPO, EQT is required to indemnify the Partnership for losses relating to its failure to have any consent or governmental permit where such failure prevents the Partnership from using or operating its assets in substantially the same manner that such assets were used and operated immediately prior to the closing of the IPO.
• Taxes. Until 60 days after the expiration of any applicable statute of limitations, EQT will indemnify the Partnership for any income taxes attributable to operations or ownership of the assets prior to the closing of the IPO, including any such income tax liability of EQT and its affiliates that may result from the Partnership’s formation transactions.
• Retained liabilities. EQT is required to indemnify the Partnership for any liabilities, claims or losses relating to or arising from assets owned or previously owned by the Partnership and retained by EQT and its affiliates following the closing of the IPO.
• Big Sandy Pipeline. EQT is required to indemnify the Partnership for any claims related to Equitrans’ previous ownership of the Big Sandy Pipeline, which was sold to a third party, including claims arising under the Big Sandy Purchase Agreement.
• Contractual Offsets. EQT is required to indemnify the Partnership for any amounts owed to the Partnership by a third party that has exercised a contractual right of offset against amounts owed by EQT to such third party.
In no event is EQT obligated to indemnify the Partnership for any claims, losses or expenses or income taxes referred to in the first seven bullets above to the extent either (i) reserved for in the Partnership’s financial statements as of December 31, 2011, or (ii) the Partnership recovers any such amounts under available insurance coverage, from contractual rights or other recoveries against any third party or in the tariffs paid by the customers of the Partnership’s affected pipeline system.
The Partnership indemnifies EQT for all losses attributable to (i) the post-closing operations of the assets retained by the Partnership, to the extent not subject to EQT’s indemnification obligations; and (ii) any amounts owed to EQT by a third party that has exercised a contractual right of offset against amounts owed by the Partnership to such third party.
The table below sets forth the amounts and categories of obligations described above for which EQT was obligated to indemnify and/or reimburse the Partnership pursuant to the omnibus agreement for the year ended December 31, 2013.
|
DESCRIPTION OF OBLIGATION |
|
AMOUNT OF OBLIGATION (IN MILLIONS) |
|
Plugging and abandonment liabilities |
|
$ 0.6 |
|
Bare steel replacement |
|
$ 2.6 |
Competition
Under the Partnership’s partnership agreement, EQT and its affiliates are expressly permitted to compete with the Partnership. EQT and any of its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future without any obligation to offer the Partnership the opportunity to purchase or construct those assets.
Amendment and Termination
The omnibus agreement can be amended by written agreement of all parties to the agreement. However, the Partnership may not agree to any amendment or modification that would, in the determination of the Partnership’s general partner, be adverse in any material respect to the holders of the Partnership’s common units without the prior approval of the conflicts committee. In the event of (i) a “change in control” (as defined in the omnibus agreement) of the Partnership, the Partnership’s general partner or EQT or (ii) the removal of EQT Midstream Services, LLC as the Partnership’s general partner in circumstances where (a) “cause” (as defined in the Partnership’s partnership agreement) does not exist and the common units held by the Partnership’s general partner and its affiliates were not voted in favor of such removal or (b) cause exists, the omnibus agreement (other than the indemnification and
reimbursement provisions therein) will be terminable by EQT, and the Partnership will have a 90-day transition period to cease the Partnership’s use of the name “EQT” and related marks.
Operation and Management Services Agreement
Upon the closing of the IPO, the Partnership entered into an operation and management services agreement with EQT Gathering, LLC (EQT Gathering) an indirect, wholly-owned subsidiary of EQT, under which EQT Gathering provides the Partnership’s pipelines and storage facilities with certain operational and management services, such as operation and maintenance of flow and pressure control, maintenance and repair of the Partnership’s pipeline and storage facilities, conducting routine operational activities, managing transportation and logistics, contract administration, gas control and measurement, engineering support and such other services as the Partnership and EQT Gathering may mutually agree upon from time to time. The Partnership reimburses EQT Gathering for such services pursuant to the terms of the omnibus agreement as described above.
The operation and management services agreement will terminate upon the termination of the omnibus agreement. If a force majeure event prevents a party from carrying out its obligations (other than to make payments due), such party’s obligations under the agreement, to the extent affected by force majeure, will be suspended during the continuation of the force majeure event. These force majeure events include acts of God, strikes, lockouts or other industrial disturbances, wars, riots, fires, floods, storms, explosions, terrorist acts, breakage or accident to machinery or lines of pipe and inability to obtain or unavoidable delays in obtaining material, equipment or supplies and similar events or circumstances, so long as such events or circumstances are beyond the reasonable control of the party claiming force majeure and could not have been prevented or overcome by such party’s reasonable diligence.
Under the agreement, EQT Gathering is required to indemnify the Partnership from claims, losses or liabilities incurred by the Partnership, including third party claims, arising out of EQT Gathering’s gross negligence or willful misconduct. The Partnership is required to indemnify EQT Gathering from any claims, losses or liabilities incurred by EQT Gathering, including any third-party claims, arising from the performance of the agreement, but not to the extent of losses or liabilities caused by EQT Gathering’s gross negligence or willful misconduct. Neither party is liable for any consequential, incidental or punitive damages under the agreement, except to the extent such damages are included in a third party claim for which a party is obligated to indemnify the other party pursuant to the agreement. Neither party may assign its rights or obligations under the agreement without the prior written consent of the other party, which shall not be unreasonably withheld, conditioned or delayed.
Contracts with Affiliates
Transportation Service and Precedent Agreements
For the years ended December 31, 2013, 2012 and 2011, the Partnership’s transportation agreements with EQT accounted for approximately 80%, 84% and 84%, respectively, of the natural gas throughput on the Partnership’s transmission system and 80%, 81% and 83%, respectively, of the Partnership’s transmission revenues. EQT Energy, a wholly-owned subsidiary of EQT, has contracted for firm transmission capacity of 710 BBtu per day on the Partnership’s transmission and storage system with a primary term through August of 2023. The reserved capacity under this contract will decrease to 305 BBtu on July 1, 2023.
EQT Energy’s firm transportation agreement will automatically renew for one year periods upon the expiration of the primary term, subject to six months prior written notice by either party to terminate. In addition, the Partnership has also entered into an agreement with EQT Energy to provide interruptible transmission service, which is currently renewing automatically for one month periods, subject to 30 days prior written notice by either party to terminate.
In May of 2013, EQT Energy entered into a precedent agreement for 295 BBtu per day of firm transmission capacity on the Sunrise Pipeline. The firm transmission capacity will become available upon completion of a compression expansion project at the Partnership’s Jefferson Compressor, which the Partnership expects to be completed by the third quarter of 2014.
On December 19, 2012, EQT and a direct wholly owned subsidiary, Distribution Holdco, LLC, entered into a Master Purchase Agreement with PNG Companies LLC (PNG Companies), the parent company of Peoples Natural Gas Company LLC, to transfer 100% ownership of EQT’s LDC, Equitable Gas Company, LLC (Equitable Gas Company) to PNG Companies (the “Equitable Gas Transaction”). The parties completed the Equitable Gas Transaction on December 17, 2013. As consideration for the Equitable Gas Transaction, EQT received cash proceeds of approximately $740 million, which is subject to certain post-closing adjustments, select midstream assets, including an approximately 200 mile FERC-regulated natural gas transmission pipeline that interconnects with the Partnership’s transmission and storage system, referred to as the AVC facilities, and commercial arrangements with the PNG Companies and its affiliates.
Prior to the completion of the Equitable Gas Transaction, Equitable Gas Company had contracts for an aggregate peak winter firm transmission capacity of 448 BBtu per day on the Partnership’s transmission and storage system, pursuant to firm transportation agreements at the maximum rates specified in the Partnership’s tariff, including two service agreements under the Partnership’s no-notice firm transportation rate schedule, which features a higher maximum tariff rate than the Partnership’s customary firm transportation service. Upon the completion of the Equitable Gas Transaction, the primary terms of Equitable Gas Company’s firm transportation service agreements and no-notice firm transportation service agreements were extended through March of 2034.
Storage Agreements
Prior to the Equitable Gas Transaction, the Partnership provided firm storage services to Equitable Gas Company under four firm storage service agreements at the maximum rates specified in the Partnership’s tariff. Upon the completion of the Equitable Gas Transaction, the primary terms of Equitable Gas Company’s firm storage service agreements were extended through March of 2034. These agreements automatically renew for one year periods upon the expiration of the primary term, subject to 12 months prior written notice by either party to terminate. The aggregate annual storage capacity subscribed under these firm storage agreements with Equitable Gas Company is equal to 13.5 TBtu. For the years ended December 31, 2013, 2012 and 2011, Equitable Gas Company accounted for approximately 56%, 45% and 39%, respectively, of the Partnership’s storage revenues.
Gas Gathering Agreements
The Partnership has entered into two gas gathering agreements with EQT Energy. Prior to the Equitable Gas Transaction, the Partnership also provided gas gathering services to Equitable Gas Company under a gas gathering agreement. These agreements have a primary term of one year and renew automatically for one month periods, subject to 30 days prior written notice by either party to terminate. Service provided under these gathering agreements is fee-based at the rate specified in the Partnership’s tariff. These gathering agreements accounted for approximately 53%, 63% and 63%, respectively, of the Partnership’s gathering throughput for the years ended December 31, 2013, 2012 and 2011. For the years ended December 31, 2013, 2012 and 2011, EQT accounted for approximately 54%, 64% and 64%, respectively, of the Partnership’s gathering revenues in each year.
The table below sets forth the revenues recognized by the Partnership with respect to the transportation, storage and gathering agreements described above with EQT for the year ended December 31, 2013.
|
DESCRIPTION OF REVENUE |
|
REVENUES (IN |
|
|
Transmission and storage |
|
$ 136.0 |
|
|
Gathering |
|
$ 6.4 |
|
Asset Exchange Agreement
In connection with the Equitable Gas Transaction, EQT, Equitable Gas and Equitrans entered into an Asset Exchange Agreement, pursuant to which the parties transferred and exchanged to one another certain assets prior to the closing of the transfer of Equitable Gas. The asset transfers involving Equitrans consisted of (a) the transfer from Equitrans to Equitable Gas of the natural gas pipelines known as the Pennsylvania Gathering Pipelines, Tombaugh Gathering Pipeline, the M-85 Transmission Pipeline, the H-153 Transmission Pipeline and the Crooked Creek property, and (b) the transfer from Equitable Gas to Equitrans of the natural gas pipeline known as the D-494 Transmission Pipeline.
Sunrise Merger Agreement
On July 15, 2013, the Partnership and Equitrans entered into an Agreement and Plan of Merger with EQT and Sunrise, a wholly owned subsidiary of EQT and the owner of the Sunrise Pipeline. Effective July 22, 2013, Sunrise merged with and into Equitrans, with Equitrans continuing as the surviving company. The Partnership paid EQT consideration of $540 million, consisting of a $507.5 million cash payment, 479,184 Partnership common units and 267,942 Partnership general partner units. Prior to the Sunrise Merger, Equitrans entered into a precedent agreement with a third party for firm transportation service on the Sunrise Pipeline over a twenty-year term (the “Precedent Agreement”). Pursuant to the Agreement and Plan of Merger, the Partnership made an additional payment of $110 million to EQT in January 2014 following the effectiveness of the transportation agreement contemplated by the Precedent Agreement.
Prior to the Sunrise Merger, the Partnership operated the Sunrise Pipeline as part of its transmission and storage system under a lease agreement with EQT. The lease was a capital lease under GAAP and, as a result, revenues and expenses associated with Sunrise were included in the Partnership’s consolidated financial statements. Effective as of the closing of the Sunrise Merger, the lease agreement was terminated.
AVC Lease
In connection with EQT’s acquisition of the AVC facilities in the Equitable Gas Transaction, the Partnership entered into a lease agreement with EQT pursuant to which the Partnership markets the capacity, enters into all agreements for transportation service with customers and operates the AVC facilities according to the terms of its tariff. The Partnership makes lease payments to EQT based on revenues collected and the actual cost to operate the AVC facilities. As a result, the AVC Lease is not expected to have a net positive or negative impact on distributable cash flow. Upon termination of the AVC Lease agreement, the Partnership will have the option to purchase the AVC facilities at a price to be negotiated between the parties. The lease payments related to 2013 totaled $1.0 million.
EQT Corporation Guaranty
EQT has entered into a guaranty agreement to guarantee all payment obligations, plus interest and any other charges, due and payable by EQT Energy to Equitrans pursuant to the agreements discussed above, up to $50 million. This guaranty will terminate on November 30, 2023 unless terminated earlier by EQT by providing 10 days written notice.
Acreage Dedication
Pursuant to an acreage dedication to the Partnership by EQT, effective as of March 1, 2011, the Partnership has the right to elect to transport, at a negotiated rate, which will be the higher of a market or cost of service rate, all natural gas produced from wells drilled by EQT on the dedicated acreage, which is an area covering approximately 60,000 acres surrounding the Partnership’s storage assets in Allegheny, Washington and Greene counties in Pennsylvania and Wetzel, Marion, Taylor, Tyler, Doddridge, Harrison and Lewis counties in West Virginia. The acreage dedication is contained in a sublease agreement in which the Partnership granted to EQT all of the oil and gas interests, including the exclusive rights to drill, explore for, produce and market such oil and gas, the Partnership had received as part of certain of its oil and gas leasehold estates the Partnership uses for gas storage and protection. Furthermore, if EQT acquires acreage with natural gas storage rights within the area of mutual interest established by the acreage dedication, then EQT will enter into an agreement with the Partnership to permit it to store natural gas on such acreage. Likewise, if the Partnership acquires acreage within the area of mutual interest with natural gas or oil production, development, marketing and exploration rights, such acreage will automatically become subject to EQT’s rights under the acreage dedication.
Review, Approval or Ratification of Transactions with Related Persons
The board of directors of the Partnership’s general partner has adopted a related person transaction approval policy that establishes procedures for the identification, review and approval of related person transactions. Pursuant to the policy, the management of the Partnership’s general partner is charged with primary responsibility
for determining whether, based on the facts and circumstances, a proposed transaction is a related person transaction.
For purposes of the policy, a “Related Person” is any director or executive officer of the Partnership’s general partner, any nominee for director, any unitholder known to the Partnership to be the beneficial owner of more than 5% of any class of the Partnership’s voting securities, and any immediate family member of any such person. A “Related Person Transaction” is generally a transaction in which the Partnership is, or the Partnership’s general partner or any of its subsidiaries is, a participant, where the amount involved exceeds $120,000, and a Related Person has a direct or indirect material interest. Transactions resolved under the conflicts provision of the partnership agreement are not required to be reviewed or approved under the policy. Please read “Conflicts of Interest” below.
To assist management in making this determination, the policy sets forth certain categories of transactions that are deemed to be pre-approved by the board under the policy. The transactions which are automatically pre-approved include (i) transactions involving employment of the Partnership’s executive officers, as long as the executive officer is not an immediate family member of another of the Partnership’s executive officers or directors and the compensation paid to such executive officer was approved by the board; (ii) transactions involving compensation and benefits paid to the Partnership’s directors for service as a director; (iii) transactions on competitive business terms with another company in which a director or immediate family member of the director’s only relationship is as an employee or executive officer, a director, or beneficial owner of less than 10% of that company’s shares, provided that the amount involved does not exceed the greater of $1,000,000 or 2% of the other company’s consolidated gross revenues; (iv) transactions where the interest of the Related Person arises solely from the ownership of a class of equity securities of the Partnership, and all holders of that class of equity securities receive the same benefit on a pro rata basis; (v) transactions where the rates or charges involved are determined by competitive bids; (vi) transactions involving the rendering of services as a common or contract carrier or public utility at rates or charges fixed in conformity with law or governmental regulation; (vii) transactions involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture or similar services; and (viii) any charitable contribution, grant or endowment by the Partnership or any affiliated charitable foundation to a charitable or non-profit organization, foundation or university in which a Related Person’s only relationship is as an employee or a director or trustee, if the aggregate amount involved does not exceed the greater of $1,000,000 or 2% of the recipient’s consolidated gross revenues.
If, after applying these categorical standards and weighing all of the facts and circumstances, management determines that a proposed transaction is a related person transaction, management must present the proposed transaction to the board of directors of the Partnership’s general partner for review or, if impracticable under the circumstances, to the chairman of the board. The board must then either approve or reject the transaction in accordance with the terms of the policy taking into account all facts and circumstances including, (i) the benefits to the Partnership of the transaction; (ii) the terms of the transaction; (iii) the terms available to unaffiliated third parties and employees generally; (iv) the extent of the affected director or executive officer’s interest in the transaction; and (v) the potential for the transaction to affect the individual’s independence or judgment. The board of the Partnership’s general partner may, but is not required to, seek the approval of the conflicts committee for the resolution of any related person transaction.
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between the Partnership’s general partner and its affiliates, including EQT, on the one hand, and the Partnership and its limited partners, on the other hand. The directors and officers of the Partnership’s general partner have fiduciary duties to manage the Partnership’s general partner in a manner beneficial to its owners. At the same time, the Partnership’s general partner has a duty to manage the Partnership in a manner beneficial to the Partnership and its limited partners. The Delaware Revised Uniform Limited Partnership Act, which the Partnership refers to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, the Partnership’s partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by its general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. The Partnership’s partnership agreement also specifically
defines the remedies available to limited partners for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.
Whenever a conflict arises between the Partnership’s general partner or its affiliates, on the one hand, and the Partnership or any other partner, on the other, the Partnership’s general partner will resolve that conflict. The Partnership’s general partner may seek the approval of such resolution from the conflicts committee of the board of directors of its general partner. There is no requirement that the Partnership’s general partner seek the approval of the conflicts committee for the resolution of any conflict, and, under the Partnership’s partnership agreement, the Partnership’s general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by the partnership agreement, as described below, in its sole discretion. The Partnership’s general partner will decide whether to refer the matter to the conflicts committee on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution.
The Partnership’s general partner will not be in breach of its obligations under the partnership agreement or its duties to the Partnership or its limited partners if the resolution of the conflict is:
• approved by the conflicts committee;
• approved by the vote of a majority of the outstanding common units, excluding any common units owned by the Partnership’s general partner or any of its affiliates;
• determined by the board of directors of the Partnership’s general partner to be on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties; or
• determined by the board of directors of the Partnership’s general partner to be fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to the Partnership.
If the Partnership’s general partner does not seek approval from the conflicts committee and the board of directors of the Partnership’s general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors of the Partnership’s general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in the Partnership’s partnership agreement, the Partnership’s general partner or the conflicts committee of the general partner’s board of directors may consider any factors it determines in good faith to consider when resolving a conflict. When the Partnership’s partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he is acting in the best interests of the Partnership or meets the specified standard, for example, a transaction on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties.
Director Independence
The NYSE does not require a listed publicly traded limited partnership, such as the Partnership, to have a majority of independent directors on the board of directors of its general partner. To assist it in determining the independence of the directors of the Partnership’s general partner, the Board established guidelines, which are included in its corporate governance guidelines and conform to the independence requirements under the NYSE listing standards. For a discussion of the independence of the board of directors of the Partnership’s general partner, please see Item 10, “Directors, Executive Officers and Corporate Governance-Committees of the Board of Directors.”
Item 14. Principal Accounting Fees and Services
Ernst & Young LLP served as the Partnership’s independent auditor for the year ended December 31, 2013. The following chart details the fees billed to the Partnership by Ernst & Young LLP during 2013 and 2012:
|
|
|
2013 |
|
2012 |
|
|
Audit Fees |
$ |
387 |
$ |
306 |
|
|
Audit-Related Fees |
|
375 |
|
0 |
|
|
Tax Fees |
|
0 |
|
0 |
|
|
All Other Fees |
|
0 |
|
0 |
|
|
Total |
$ |
762 |
$ |
306 |
|
Audit fees include fees for the audit of the Partnership’s annual financial statements, reviews of the Partnership’s financial statements included in the Partnership’s quarterly reports, and services that are normally provided in connection with statutory and regulatory filings or engagements, including subsidiary attest engagements and consents. Audit-related fees for 2013 include fees associated with the Partnership’s acquisition of the Sunrise Pipeline.
Certain fees approved by EQT and reimbursed by the Partnership from IPO proceeds are not included in the above amounts. The excluded amounts total $0.6 million for 2012 and are solely attributable to audit fees and audit-related fees for the Partnership’s Predecessor for periods prior to its IPO.
The audit committee of the Partnership’s general partner has adopted a policy regarding the services of its independent auditors under which the Partnership’s independent accounting firm is not allowed to perform any service which may have the effect of jeopardizing the registered public accountant’s independence. Without limiting the foregoing, the independent accounting firm shall not be retained to perform the following:
• Bookkeeping or other services related to the accounting records or financial statements
• Financial information systems design and implementation
• Appraisal or valuation services, fairness opinions or contribution-in-kind reports
• Actuarial services
• Internal audit outsourcing services
• Management functions
• Human resources functions
• Broker-dealer, investment adviser or investment banking services
• Legal services
• Expert services unrelated to the audit
• Prohibited tax services
All audit and permitted non-audit services must be pre-approved by the audit committee. The audit committee has delegated specific pre-approval authority with respect to permitted non-audit services to the Chair of the audit committee but only where pre-approval is required to be acted upon prior to the next audit committee meeting and where the aggregate permitted non-audit services fees are not more than $75,000. The audit committee encourages management to seek pre-approval from the audit committee at its regularly scheduled meetings. In 2013, 100% of the professional fees reported as audit-related fees were pre-approved pursuant to the above policy.
The audit committee has approved the appointment of Ernst & Young LLP as the Partnership’s independent auditor to conduct the audit of the Partnership’s consolidated financial statements for the year ended December 31, 2014.
Item 15. Exhibits and Financial Statement Schedules
|
(a) |
1. |
Financial Statements |
|
|
|
The financial statements listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K. |
|
|
|
|
|
|
2. |
Financial Statement Schedules |
|
|
|
All schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules. |
|
|
|
|
|
|
3. |
Exhibits |
|
|
|
The exhibits listed on the accompanying index to exhibits (pages 119 through 121) are filed as part of this Annual Report on Form 10-K. |
EQT MIDSTREAM PARTNERS, LP
INDEX TO FINANCIAL STATEMENTS COVERED
BY REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
1. The following Consolidated Financial Statements of EQT Midstream Partners, LP and Subsidiaries are included in Item 8:
|
|
|
Page Reference |
|
|
|
|
|
|
68 | |
|
|
69 | |
|
Consolidated Balance Sheets as of December 31, 2013 and 2012 |
|
70 |
|
|
71 | |
|
|
72 |
|
Exhibits |
|
Description |
|
Method of Filing |
|
2.1 |
|
Agreement and Plan of Merger by and among EQT Investments Holdings, LLC, EQT Midstream Services, LLC, Sunrise Pipeline, LLC, EQT Midstream Partners, LP and Equitrans, LP, dated as of July 15, 2013. The Partnership will furnish supplementally a copy of any omitted schedule and similar attachment to the Commission upon request. |
|
Filed as Exhibit 2.1 to Form 8-K (#001-35574) filed on July 15, 2013. |
|
|
|
|
|
|
|
3.1 |
|
Certificate of Limited Partnership of EQT Midstream Partners, LP. |
|
Filed as Exhibit 3.1 to Form S-1 Registration Statement (#333-179487) filed on February 13, 2012. |
|
|
|
|
|
|
|
3.2 |
|
First Amended and Restated Agreement of Limited Partnership of EQT Midstream Partners, LP, dated July 2, 2012. |
|
Filed as Exhibit 3.2 to Form 8-K (#001-35574) filed on July 2, 2012. |
|
|
|
|
|
|
|
3.3 |
|
Certificate of Formation of EQT Midstream Services, LLC. |
|
Filed as Exhibit 3.3 to Form S-1 Registration Statement (#333-179487) filed on February 13, 2012. |
|
|
|
|
|
|
|
3.4 |
|
First Amended and Restated Limited Liability Company Agreement of EQT Midstream Services, LLC, dated July 2, 2012. |
|
Filed as Exhibit 3.4 to Form 8-K (#001-35574) filed on July 2, 2012. |
|
|
|
|
|
|
|
10.1 |
|
Contribution, Conveyance and Assumption Agreement, dated July 2, 2012, by and among EQT Midstream Partners, LP, EQT Midstream Services, LLC, Equitrans Investments, LLC, Equitrans, L.P., Equitrans Services, LLC, EQT Midstream Investments, LLC, EQT Investments Holdings, LLC, ET Blue Grass, LLC and EQT Corporation. |
|
Filed as Exhibit 10.1 to Form 8-K (#001-35574) filed on July 2, 2012. |
|
|
|
|
|
|
|
10.2 |
|
Omnibus Agreement, dated July 2, 2012, by and among the EQT Midstream Partners, LP, EQT Midstream Services, LLC and EQT Corporation. |
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Filed as Exhibit 10.2 to Form 8-K (#001-35574) filed on July 2, 2012. |
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10.3 |
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Operation and Management Services Agreement, dated July 2, 2012, by and among Equitrans, L.P. and EQT Gathering, LLC. |
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Filed as Exhibit 10.3 to Form 8-K (#001-35574) filed on July 2, 2012. |
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10.4 |
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Amended and Restated Revolving Credit Agreement, dated February 18, 2014, by and among EQT Midstream Partners, LP, Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders named therein. |
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Filed as Exhibit 10.1 to Form 8-K (#001-35574) filed on February 18, 2014. |
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10.5 |
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EQT Midstream Services, LLC 2012 Long-Term Incentive Plan, dated July 2, 2012. |
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Filed as Exhibit 10.5 to Form 8-K (#001-35574) filed on July 2, 2012. |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
INDEX TO EXHIBITS
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Exhibits |
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Description |
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Method of Filing |
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10.6* |
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Form of Phantom Unit Award Agreement. |
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Filed as Exhibit 10.6 to Amendment No. 2 to Form S-1 Registration Statement (#333-179487) filed on May 10, 2012. |
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10.7* |
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Form of TSR Performance Award Agreement. |
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Filed as Exhibit 10.7 to Amendment No. 2 to Form S-1 Registration Statement (#333-179487) filed on May 10, 2012. |
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10.8 |
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Form of Transportation Service Agreement Applicable to Firm Transportation Service Under Rate Schedule FTS between Equitrans, L.P. and Equitable Gas Company, LLC. |
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Filed as Exhibit 10.9 to Amendment No. 2 to Form S-1 Registration Statement (#333-179487) filed on May 10, 2012. |
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10.9 |
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Form of Transportation Service Agreement Applicable to No-Notice Firm Transportation Service Under Rate Schedule NOFT between Equitrans, LP and Equitable Gas Company, LLC. |
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Filed as Exhibit 10.10 to Amendment No. 2 to Form S-1 Registration Statement (#333-179487) filed on May 10, 2012. |
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10.10 |
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Agreement to Extend Services Agreements between Equitrans, LP and Equitable Gas Company, LLC. |
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Filed herewith as Exhibit 10.10. |
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10.11 |
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EQT Guaranty dated April 25, 2012, executed by EQT Corporation in favor of Equitrans, L.P. |
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Filed as Exhibit 10.11 to Amendment No. 2 to Form S-1 Registration Statement (#333-179487) filed on May 10, 2012. |
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10.12 |
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Sublease Agreement between Equitrans, L.P. and EQT Production Company, effective March 1, 2011. |
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Filed as Exhibit 10.12 to Amendment No. 2 to Form S-1 Registration Statement (#333-179487) filed on May 10, 2012. |
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10.13 |
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Amendment of Sublease Agreement between Equitrans, L.P. and EQT Production Company, dated April 5, 2012. |
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Filed as Exhibit 10.13 to Amendment No. 2 to Form S-1 Registration Statement (#333-179487) filed on May 10, 2012. |
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10.14* |
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Form of Director Indemnification Agreement. |
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Filed as Exhibit 10.15 to Amendment No. 3 to Form S-1 Registration Statement (#333-179487) filed on June 5, 2012. |
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10.15 |
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Sunrise Facilities Amended and Restated Lease Agreement between Equitrans, L.P. and Sunrise Pipeline, L.L.C., as amended and restated as of October 25, 2012. |
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Filed as Exhibit 10.19 to Form 10-Q (#001-35574) for the quarterly period ended September 30, 2012. |
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10.16 |
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Transportation Service Agreement Applicable to Firm Transportation Service Under Rate Schedule FTS between Equitrans, LP and EQT Energy, LLC, dated December 20, 2013, Contract No. EQTR 18679-852. |
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Filed herewith as Exhibit 10.16. |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
INDEX TO EXHIBITS
|
Exhibits |
|
Description |
|
Method of Filing |
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10.17 |
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Sunrise Expansion Precedent Agreement, dated May 30, 2013, between Equitrans, LP and EQT Energy, LLC. |
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Filed herewith as Exhibit 10.17. |
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21.1 |
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List of Subsidiaries of EQT Midstream Partners, LP. |
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Filed herewith as Exhibit 21.1. |
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23.1 |
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Consent of Independent Registered Public Accounting Firm. |
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Filed herewith as Exhibit 23.1. |
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31.1 |
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Rule 13(a)-14(a) Certification of Principal Executive Officer. |
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Filed herewith as Exhibit 31.1. |
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31.2 |
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Rule 13(a)-14(a) Certification of Principal Financial Officer. |
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Filed herewith as Exhibit 31.2. |
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32 |
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Section 1350 Certification of Principal Executive Officer and Principal Financial Officer. |
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Filed herewith as Exhibit 32. |
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101 |
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Interactive Data File. |
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Filed herewith as Exhibit 101. |
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Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)
Pursuant to the requirements of Section 13 or 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.
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EQT Midstream Partners, LP | |
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By: EQT Midstream Services, LLC, its General Partner | |
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By: |
/s/ DAVID L. PORGES |
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David L. Porges |
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Chairman, President and Chief Executive Officer |
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February 20, 2014 |
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.
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/s/ DAVID L. PORGES |
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Chairman, President, and Chief Executive Officer |
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February 20, 2014 |
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David L. Porges |
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(Principal Executive Officer) |
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/s/ PHILIP P. CONTI |
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Director, Senior Vice President and Chief Financial Officer |
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February 20, 2014 |
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Philip P. Conti |
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(Principal Financial Officer) |
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/s/ THERESA Z. BONE |
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Vice President, Finance and Chief Accounting Officer |
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February 20, 2014 |
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Theresa Z. Bone |
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(Principal Accounting Officer) |
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/s/ JULIAN M. BOTT |
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Director |
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February 20, 2014 |
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Julian M. Bott |
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/s/ MICHAEL A. BRYSON |
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Director |
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February 20, 2014 |
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Michael A. Bryson |
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/s/ RANDALL L. CRAWFORD |
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Director |
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February 20, 2014 |
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Randall L. Crawford |
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/s/ LEWIS B. GARDNER |
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Director |
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February 20, 2014 |
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Lewis B. Gardner |
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/s/ LARA E. WASHINGTON |
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Director |
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February 20, 2014 |
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Lara E. Washington |
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