Item 1. Legal Proceedings
See
Note 12
–
Legal and Environmental Matters
to the condensed combined financial statements included in Part I—Item 1.—Financial Statements of this Quarterly Report, which is incorporated here by reference.
Item 1A. Risk Factors
You should consider carefully the following risk factors, together with all of the other information included in this Quarterly Report, in your evaluation of an investment in our Class A shares. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations. In that case, we might not be able to pay or sustain our estimated annualized initial quarterly distribution on our Class A shares, the trading price of our Class A shares could decline and you could lose all or part of your investment. References to “us,” “we,” and “our” in this Item 1A refer to Tallgrass Energy GP, LP in its individual capacity.
Risks Inherent in an Investment in Us
Our only cash-generating assets are our interests in Tallgrass Equity and therefore our cash flow is entirely dependent upon the ability of TEP to make cash distributions to Tallgrass Equity, and the ability of Tallgrass Equity to make cash distributions to us.
We currently anticipate that the only source of our earnings and cash flow will be cash distributions from Tallgrass Equity, which will consist exclusively of cash distributions from TEP. The amount of cash that TEP will be able to distribute to its partners, including Tallgrass Equity, each quarter principally depends upon the amount of cash it generates from its business. For a description of certain factors that can cause fluctuations in the amount of cash that TEP generates from its business, please read the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” TEP may not have sufficient available cash each quarter to continue paying distributions at its current level or at all. If TEP reduces its per unit distribution, either because of reduced operating cash flow, higher expenses, capital requirements or otherwise, we will have less cash available for distribution to you and would likely be required to reduce our per share distribution to you. You should also be aware that the amount of cash TEP has available for distribution depends primarily upon
TEP’s distributable cash flow, including cash flow from the release of financial reserves as well as borrowings, not profitability, which will be affected by non-cash items. As a result, TEP may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records profits.
Furthermore, Tallgrass Equity’s ability to distribute cash to us and our ability to distribute cash received from Tallgrass Equity to our Class A shareholders is limited by a number of factors, including:
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Tallgrass Equity’s payment of costs and expenses associated with our, our general partner's, Holdings', and Tallgrass Equity’s respective operations, including expenses we incur as a result of being a public company, which costs and expenses are not subject to a limit pursuant to the Omnibus Agreement, dated May 12, 2015 (the “TEGP Omnibus Agreement”);
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our payment of any income taxes;
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interest expense and principal payments on any indebtedness incurred by TEP, Tallgrass Equity, TEP GP or us;
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restrictions on distributions contained in Tallgrass Equity’s and TEP’s respective revolving credit facilities and any future debt agreements entered into by Tallgrass Equity, TEP, TEP GP or us;
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reserves created by our general partner as necessary to permit Tallgrass Equity to make required capital contributions to TEP GP for it to maintain or attain up to a 2.0% general partner interest in TEP; and
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reserves our general partner or TEP GP establish for the proper conduct of our, Tallgrass Equity’s or TEP’s business, including reserves to comply with applicable law or any agreement binding on us, our subsidiaries, Tallgrass Equity, Tallgrass Equity’s subsidiaries, TEP and TEP’s subsidiaries, which reserves are not subject to a limit pursuant to our partnership agreement, TEP’s partnership agreement or Tallgrass Equity’s limited liability company agreement.
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A material increase in amounts paid or reserved with respect to any of these factors could restrict our ability to pay quarterly distributions to our Class A shareholders.
We may limit or modify the incentive distributions that Tallgrass Equity is entitled to receive through its ownership of TEP’s incentive distribution rights without the consent of our shareholders, which may reduce cash distributions to you.
We own a 30.35% membership interest in Tallgrass Equity, which, through its ownership of all the membership interests in TEP GP, is entitled to receive increasing percentages (up to a maximum of 48%, to the extent not modified) of any cash distributed by TEP in excess of $0.3048 per TEP common unit in any quarter. The majority of the cash flow we receive from Tallgrass Equity is expected to be derived from its ownership of these IDRs.
TEP, like other publicly traded partnerships, generally targets acquisitions or expansion capital projects that, after giving effect to related costs and expenses, would be expected to be accretive, meaning it would increase cash distributions per unit in future periods. Because Tallgrass Equity, through its ownership of TEP GP, currently participates in the IDRs at all levels, including the highest sharing level of 48%, it is harder for an acquisition or capital project to show accretion for the common unitholders of TEP than if the IDRs received less incremental cash flow. As a result, our general partner may cause TEP’s general partner to modify or reduce the IDRs to facilitate a particular acquisition or expansion capital project. Any such reduction or modification of IDRs will reduce the amount of cash that would have otherwise been distributed by Tallgrass Equity to us, which will in turn reduce the cash distributions we would otherwise be able to pay to you. Our shareholders are not able to vote on or otherwise prohibit TEP’s general partner from modifying the TEP IDRs, and our general partner may cause TEP’s general partner to reduce or modify the IDRs without considering the interests of the holders of our Class A shares. In addition, there can be no guarantee that the expected benefits of any IDR reduction or modification will be realized.
A reduction in TEP’s distributions will disproportionately affect the amount of cash distributions to which Tallgrass Equity is currently entitled.
Tallgrass Equity’s indirect ownership of TEP’s IDRs entitle it to receive increasing percentages, ranging from 13% up to 48%, to the extent not reduced or modified, of all cash distributed by TEP in excess of $0.3048 per TEP common unit per quarter. A decrease in the amount of distributions paid by TEP to less than $0.4313 per TEP common unit per quarter would reduce Tallgrass Equity’s percentage of incremental cash distributions in excess of $0.3048 per TEP common unit per quarter from 48% to as low as 13%. A decrease in the amount of distributions paid by TEP to less than $0.3048 per TEP common unit per quarter would result in Tallgrass Equity not receiving any incremental cash distributions with respect to the IDRs for such quarter. As a result, any such reduction in quarterly cash distributions from TEP would have the effect of disproportionately reducing the amount of distributions that Tallgrass Equity receives from TEP in respect of the IDRs as compared to cash distributions TEP makes with respect to its common units and general partner interest.
Our distributions to our Class A shareholders are not cumulative.
Our distributions to our Class A shareholders are not cumulative. Consequently, if distributions on our Class A shares are not paid with respect to any fiscal quarter then our Class A shareholders will not be entitled to receive that quarter’s payments in the future.
The amount of cash that we and TEP distribute each quarter may limit our ability to grow.
Because we distribute all of our available cash, our growth may not be as fast as the growth of businesses that reinvest their available cash to expand ongoing operations. In fact, because our cash flow is generated solely from distributions we receive from Tallgrass Equity, which are derived from Tallgrass Equity’s direct and indirect partnership interests in TEP, our growth is expected to initially be completely dependent upon TEP. The amount of distributions received by Tallgrass Equity is based on TEP’s per unit distribution paid on each TEP unit, the number of TEP units outstanding, and the number of TEP units owned by Tallgrass Equity. If we issue additional Class A shares, Tallgrass Equity incurs additional debt, we incur debt or we or Tallgrass Equity are required to pay taxes, the payment of distributions on those additional Class A shares or interest on that debt or payment of such taxes could increase the risk that we will be unable to maintain or increase our cash distribution levels.
Our rate of growth will be reduced to the extent we purchase additional equity interests from TEP, which will reduce the percentage of our cash flow that we receive from the IDRs.
Our business strategy includes, where appropriate, supporting the growth of TEP through the use of our capital resources, including by purchasing TEP common units or lending funds to TEP to finance acquisitions or internal growth projects. To the extent we purchase common units or securities not entitled to a current distribution from TEP, the rate of our distribution growth will be reduced, at least in the short term, because a smaller percentage of our cash distributions would come from our ownership of the IDRs, which increase at a faster rate than TEP’s common units and any similar equity interests TEP may issue in the future.
Restrictions in Tallgrass Equity’s and TEP’s respective revolving credit facilities could limit Tallgrass Equity’s ability to make distributions to us, thereby limiting our ability to make distributions to our Class A shareholders. Any credit facility we enter into in the future could pose similar restrictions that would further limit our ability to make distributions.
Tallgrass Equity’s and TEP’s respective revolving credit facilities contain various operating and financial restrictions and covenants. Tallgrass Equity’s and TEP’s respective ability to comply with these restrictions and covenants may be affected by events beyond their control, including prevailing economic, financial and industry conditions. If Tallgrass Equity or TEP is unable to comply with these restrictions and covenants, any indebtedness under these revolving credit facilities may become immediately due and payable and Tallgrass Equity’s and TEP’s respective lenders’ commitment to make further loans under these revolving credit facilities may terminate. Tallgrass Equity or TEP might not have, or be able to obtain, sufficient funds to make these accelerated payments.
Tallgrass Equity’s payment of principal and interest on indebtedness reduces its cash distributions to us, thereby reducing our cash available for distribution on our Class A shares. Tallgrass Equity’s revolving credit facility limits our ability to pay distributions to our Class A shareholders during an event of default or if an event of default would result from the distribution.
We may enter into a credit facility in the future that would impose similar restrictions to those discussed above. In addition, our payment of principal and interest on any indebtedness would reduce our cash available for distribution to our Class A shares.
For more information regarding Tallgrass Equity’s revolving credit facility, please read the section entitled “Notes to Condensed Combined Financial Statements-Subsequent Events-Tallgrass Equity Revolving Credit Facility.” For more information regarding TEP’s revolving credit facility, please see the section “-Risks Related to TEP’s Business-Restrictions in TEP’s revolving credit facility could adversely affect its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.”
Tallgrass Equity’s ownership in TEP’s IDRs, TEP’s common units and TEP’s general partner interest, are pledged under Tallgrass Equity’s revolving credit facility.
Tallgrass Equity’s direct ownership of the Acquired TEP Units and its indirect ownership of TEP’s IDRs and general partner interest are pledged as security under Tallgrass Equity’s revolving credit facility. Tallgrass Equity’s revolving credit facility contains customary and other events of default. Upon an event of default, the lenders under Tallgrass Equity’s revolving credit facility could foreclose on the IDRs in TEP, the Acquired TEP Units, and the general partner interest in TEP, which are the only assets from which our cash flows are derived. Additionally, this foreclosure would result in a change in control of TEP GP, which would constitute an immediate event of default under TEP’s credit facility. This would have a material adverse effect on our business, financial condition and results of operations.
Our shareholders do not vote in the election of our general partner’s directors. The Exchange Right Holders own a sufficient number of shares to allow them to prevent the removal of our general partner.
Our shareholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. The board of directors of our general partner, including our independent directors, is designated and elected by Holdings or its designees. Our shareholders do not have the ability to elect our general partner or the members of the board of directors of our general partner.
In addition, if our Class A shareholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. Our general partner may not be removed except by vote of the holders of at least 80% of our outstanding shares, voting together as a single class. The Exchange Right Holders own 69.95% of our outstanding shares. This ownership level enables the Exchange Right Holders to prevent our general partner’s removal.
As a result of these provisions, the price at which our shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.
If TEP’s unitholders remove TEP GP, TEP GP may be required to sell or exchange its IDRs and general partner interest and TEP GP would lose the ability to manage and control TEP.
TEP’s partnership agreement gives unitholders of TEP the right to remove TEP GP upon the affirmative vote of holders of 66 2/3% of TEP’s outstanding units. If TEP GP withdraws as general partner in compliance with TEP’s partnership agreement or is removed as general partner of TEP where cause (as defined in TEP’s partnership agreement) does not exist and a successor general partner is elected in accordance with TEP’s partnership agreement, TEP GP could elect to receive cash in exchange for its IDRs and general partner interest. If TEP GP withdraws in circumstances other than those described in the preceding sentence and a successor general partner is elected in accordance with TEP’s partnership agreement, the successor general partner will have the option to purchase the IDRs and general partner interest for their fair market value. If TEP GP or the successor general partner do not exercise their options, TEP GP’s interests would be converted into common units based on an independent valuation. In each case, TEP GP would also lose its ability to manage TEP.
In addition, if TEP GP is removed as general partner of TEP, we would face an increased risk of being deemed an investment company. Please read the section entitled “-If in the future we cease to manage and control TEP, we may be deemed to be an investment company under the Investment Company Act of 1940.”
Our general partner may cause us to issue additional Class A shares or other equity securities, including equity securities that are senior to our Class A shares, without your approval, which may adversely affect you.
Our general partner may cause us to issue an unlimited number of additional Class A shares, or other equity securities of equal rank with the Class A shares, without shareholder approval. In addition, we may issue an unlimited number of shares that are senior to our Class A shares in right of distribution, liquidation and voting. Except for Class A shares issued in connection with the exercise by any Exchange Right Holder of its right to exchange a Class B share for a Class A share (the "Exchange Right"), each of which will result in the cancellation of an equivalent number of Class B shares and therefore have no effect on the total number of outstanding shares, the issuance of additional Class A shares, or other equity securities of equal or senior rank, may have the following effects:
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each shareholder’s proportionate ownership interest in us may decrease;
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the amount of cash available for distribution on each Class A share may decrease;
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the relative voting strength of each previously outstanding Class A share may be diminished;
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the ratio of taxable income to distributions may increase; and
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the market price of the Class A shares may decline.
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You may not have limited liability if a court finds that shareholder action constitutes control of our business.
Under Delaware law, you could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our shareholders (who hold limited partner interests despite the fact that we use the term “shareholder” in this Quarterly Report) as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the “control” of our business. Additionally, the limitations on the liability of holders of limited partner interests for the liabilities of a limited partnership have not been clearly established in many jurisdictions.
Furthermore, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a shareholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
If in the future we cease to manage and control TEP we may be deemed to be an investment company under the Investment Company Act of 1940.
If we cease to indirectly manage and control TEP and are deemed to be an investment company under the Investment Company Act of 1940, we would have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contractual rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict the ability of TEP GP, Tallgrass Equity, TEP and us to borrow funds or engage in other transactions involving leverage, require us to add additional directors who are independent of us and our affiliates, and adversely affect the price of our Class A shares.
Our partnership agreement restricts the rights of shareholders owning 20% or more of our shares.
Our shareholders’ voting rights are restricted by the provision in our partnership agreement generally providing that any shares held by a person or group that owns 20% or more of any class of shares then outstanding, other than our general partner, the Exchange Right Holders or their respective affiliates and persons who acquired such shares with the prior approval of our general partner’s board of directors, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our shareholders to call meetings or to acquire information about our operations, as well as other provisions limiting our shareholders’ ability to influence the manner or direction of our management. As a result, the price at which our Class A shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.
If TEP GP, which is owned by Tallgrass Equity, is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of TEP, its value, and, therefore, the value of our Class A shares, could decline.
TEP GP and its affiliates may make expenditures on behalf of TEP for which TEP GP will seek reimbursement from TEP. Under Delaware partnership law, TEP GP has unlimited liability for the obligations of TEP, such as its debts and environmental liabilities, except for those contractual obligations of TEP that are expressly made without recourse to the general partner. To the extent TEP GP incurs obligations on behalf of TEP, it is entitled to be reimbursed or indemnified by TEP. If TEP is unable or unwilling to reimburse or indemnify TEP GP, TEP GP may not be able to satisfy those liabilities or obligations, which would reduce TEP GP’s cash distributions to Tallgrass Equity and ultimately to us for the benefit of our Class A shareholders.
Our Class A shares and TEP’s common units may not trade in relation or proportion to one another.
Our Class A shares and TEP’s common units may not trade in simple relation or proportion to one another. Instead, while the trading prices of our Class A shares and TEP’s common units are likely to follow generally similar broad trends, the trading prices may diverge because, among other things:
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TEP’s cash distributions to its common unitholders have a priority over distributions on its IDRs;
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we participate in the distributions on the IDRs and general partner interest in TEP while TEP’s common unitholders do not;
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we expect to pay federal income taxes in the future; and
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we may pursue business opportunities separate and apart from TEP or any of its affiliates.
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An increase in interest rates may cause the market price of our shares to decline.
Like all equity investments, an investment in our Class A shares is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partner interests. Reduced demand for our Class A shares resulting from investors seeking other more favorable investment opportunities may cause the trading price of our Class A shares to decline.
Future sales of our Class A shares in the public market, including sales of Class A shares by the Exchange Right Holders after the exercise of the Exchange Right, could reduce our Class A share price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
Subject to certain limitations and exceptions, the Exchange Right Holders may cause the exchange of their Tallgrass Equity units (together with a corresponding number of Class B shares) for Class A shares (on a one-for-one basis, subject to customary conversion rate adjustments for equity splits and reclassification and other similar transactions) and then sell those Class A shares. We may also issue additional Class A shares or convertible securities in subsequent public or private offerings.
We cannot predict the size of future issuances of our Class A shares or securities convertible into Class A shares or the effect, if any, that future issuances and sales of our Class A shares, including sales of Class A shares by the Exchange Right Holders after the exercise of the Exchange Right, will have on the market price of our Class A shares. Sales of substantial amounts of our Class A shares (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A shares.
The underwriters of the Offering may waive or release parties to the lock-up agreements entered into in connection with the Offering, which could adversely affect the price of our Class A shares.
Certain of our affiliates, the Exchange Right Holders and the directors and officers of our general partner have entered into lock-up agreements with respect to any sale of their Class A shares, pursuant to which they are subject to certain resale restrictions for a period of 180 days following the effective date of the registration statement filed with respect to the Offering. Citigroup Global Markets Inc. and Goldman, Sachs & Co., at any time and without notice, may release all or any portion of the Class A shares, subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then the applicable Class A shares will be available for sale into the public markets, which could cause the market price of our Class A shares to decline and impair our ability to raise capital.
Holdings has sole authority to elect the board of directors of our general partner.
Holdings has the ability to elect all of the members of our board of directors. In addition, Holdings is able to determine the outcome of all matters requiring shareholder approval, including certain mergers and other material transactions, and is able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our shareholders of an opportunity to receive a premium for their Class A shares as part of a sale of our company. The Exchange Right Holders currently own 100% of the voting interests in Holdings and entities and/or investment funds affiliated with (i) The Energy & Minerals Group, (ii) Kelso & Company and (iii) members of our and TEP’s management each have the right to designate two members of the board of managers of Holdings for so long as they maintain certain ownership percentages in Holdings. Holdings currently has a six person board of managers. Holdings continues to be able to strongly influence all matters requiring shareholder approval, regardless of whether or not shareholders believe that the transaction is in their own best interests.
A valuation allowance on our deferred tax asset could reduce our earnings.
A significant deferred tax asset was recorded as a result of certain reorganization transactions completed in connection with the Offering. GAAP requires that a valuation allowance must be established for deferred tax assets when it is more likely than not that they will not be realized. If we were to determine that a valuation allowance was appropriate for our deferred tax asset, we would be required to take an immediate charge to earnings with a corresponding reduction of partners’ equity and increase in balance sheet leverage as measured by debt to total capitalization.
The NYSE does not require a limited partnership like us or TEP to comply with certain of its corporate governance requirements.
Because we and TEP are limited partnerships, the New York Stock Exchange (the
“
NYSE”) does not require our general partner or TEP’s general partner to have a majority of independent directors on their respective board of directors. The NYSE also does not require our general partner or TEP’s general partner to establish a compensation committee or a nominating and corporate governance committee. Accordingly, our shareholders and TEP’s unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. In addition, as limited partnerships, we and TEP are not required to seek shareholder or unitholder approval, as appropriate, for issuances of Class A shares or TEP common units, respectively, including issuances in excess of 20% of outstanding equity securities, or for issuances of equity to certain affiliates.
We may incur liability as a result of our ownership of TEP’s general partner.
Under Delaware law, a general partner of a limited partnership is generally liable for the debts and liabilities of the partnership for which it serves as general partner, subject to the terms of any indemnification agreements contained in the partnership agreement and except to the extent the partnership’s contracts are non-recourse to the general partner. As a result of our structure, we indirectly own and control the general partner of TEP. To the extent the indemnification provisions in TEP’s partnership agreement or non-recourse provisions in our contracts are not sufficient to protect TEP GP from such liability, we may in the future incur liabilities as a result of our indirect ownership of TEP’s general partner. Please read the section entitled “-Risks Related to Conflicts of Interest.”
For as long as we are an emerging growth company, we are not required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.
In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to accounting standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we are not required to, among other things, (1) 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(b) of the Sarbanes Oxley Act of 2002, (2) comply with any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”) requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise, (4) provide certain disclosure regarding executive compensation required of larger public companies or (5) hold unitholder advisory votes on executive compensation.
If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.
We are required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we are required to disclose material changes made to our internal controls and procedures on a quarterly basis, we are not required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded partnership, we need to implement additional internal controls, reporting systems and procedures and may need to hire additional accounting, finance and legal staff. Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ended December 31, 2015, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our annual report for the fiscal year ending December 31, 2020 if we continue to maintain our emerging growth company status for a full five years. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, shareholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A shares.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results will be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A shares.
Risks Related to Conflicts of Interest
Our existing organizational structure and the relationships among us, TEP, our respective general partners, Holdings, the owners of Holdings, including the Exchange Right Holders, and their affiliated entities present the potential for conflicts of interest. Moreover, additional conflicts of interest may arise in the future among us and the entities affiliated with any general partner or similar interests we acquire or among TEP and such entities.
Conflicts of interest may arise as a result of our organizational structure and the relationships among us, TEP, our respective general partners, TEGP, the owners of Holdings, including the Exchange Right Holders, and their affiliated entities.
Our partnership agreement defines the duties of our general partner (and, by extension, its officers and directors). Our general partner’s board of directors or its conflicts committee has authority on our behalf to resolve any conflict involving us and they have broad latitude to consider the interests of all parties to the conflict.
Conflicts of interest may arise between us and our shareholders, on the one hand, and our general partner and its direct and indirect owners, including Holdings and the Exchange Right Holders, and affiliated entities, on the other hand, or between us and our shareholders, on the one hand, and TEP and its unitholders, on the other hand. The resolution of these conflicts may not always be in our best interest or that of our shareholders.
The Exchange Right Holders own 100% of the voting interests in Holdings and hold a majority of the combined voting power of our Class A and Class B shares.
The Exchange Right Holders own 100% of the voting interests in Holdings and hold approximately 69.65% of the combined voting power of our Class A and Class B shares . Although each of the Exchange Right Holders are entitled to act separately in their own respective interests with respect to their ownership interest in Holdings and us, the Exchange Right Holders collectively have the ability to elect all of the members of Holdings’ board of managers, each of whom serves as a member of the board of directors of our general partner. So long as any of the Exchange Right Holders continue to own a significant amount of the voting interests in Holdings, they will continue to be able to strongly influence our management and affairs.
Holdings may have interests that conflict with holders of our Class A shares.
Holdings owns our general partner and may have conflicting interests with holders of Class A shares.
Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Holdings, on the other hand, concerning, among other things, a decision whether to modify or limit the IDRs in the future or potential competitive business activities or business opportunities. These conflicts of interest may not be resolved in our favor.
Our partnership agreement replaces our general partner’s fiduciary duties to holders of our Class A shares 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 replaces 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 shareholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the shareholders 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 shareholders. Examples of decisions that our general partner may make in its individual capacity include:
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how to allocate business opportunities among us and its affiliates;
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whether to exercise its limited call right;
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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;
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how to exercise its voting rights with respect to the units it owns; and
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whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to the partnership agreement.
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In addition, our partnership agreement provides that any construction or interpretation of our partnership agreement and any action taken pursuant thereto or any determination, in each case, made by our general partner in good faith, shall be conclusive and binding on all shareholders.
By purchasing shares, you agree to become bound by the provisions in the partnership agreement, including the provisions discussed above.
Our general partner’s affiliates and Holdings may compete with us.
Our partnership agreement provides that our general partner is 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. The restrictions contained in our general partner’s limited liability company agreement are subject to a number of exceptions. For example, affiliates of our general partner, including Holdings, the Exchange Right Holders, and their respective affiliates, are not prohibited from engaging in other businesses or activities that might be in direct competition with us.
Our general partner has a call right that may require you to sell your Class A shares at an undesirable time or price.
If at any time more than 80% of our outstanding shares (including Class A shares issuable upon the exchange of Class B shares) are owned by our general partner, Holdings or their respective affiliates, our general partner has the right (which it may assign to any of its affiliates, Holdings or us), but not the obligation, to acquire all, but not less than all, of the remaining Class A shares held by public shareholders at a price equal to the greater of (x) the highest cash price paid by our general partner, Holdings, or their respective affiliates for any shares purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those shares and (y) the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed. As a result, you may be required to sell your Class A shares at an undesirable time or price and may not receive any return of or on your investment. You may also incur a tax liability upon a sale of your Class A shares.
Risks Related to TEP’s Business
TEP may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to its general partner and its affiliates, to enable it to pay the quarterly distribution at the current distribution level, or at all, to holders of its common units.
TEP may not have sufficient available cash from operating surplus each quarter to enable it to pay the quarterly distribution at the current distribution level, at the minimum quarterly distribution level, or at all. The amount of cash TEP can distribute on its units principally depends upon the amount of cash TEP generates from its operations, which will fluctuate from quarter to quarter based on, among other things:
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the level of firm transportation and storage capacity sold, the volume of natural gas and crude oil TEP transports and the volume of natural gas TEP stores, processes and treats;
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the level of production of crude oil and natural gas and the resultant market prices of natural gas, NGLs and crude oil;
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regional, domestic and foreign supply and perceptions of supply of natural gas and crude oil; the level of demand and perceptions of demand in its end-user markets; and actual and anticipated future prices of natural gas, crude oil and other commodities (and the volatility thereof), all of which may impact its ability to renew and replace firm transportation, storage and processing agreements;
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regulatory action affecting the supply of, or demand for, natural gas and crude oil, the rates TEP can charge on its assets, how TEP contracts for services, its existing contracts, its operating costs or its operating flexibility;
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changes in the fees TEP charges for its services;
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the effect of seasonal variations in temperature on the amount of natural gas and crude oil that TEP transports and the amount of natural gas that TEP stores, processes and treats;
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the realized pricing impacts on revenues and expenses that are directly related to commodity prices;
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the level of competition from other midstream energy companies in its geographic markets;
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the creditworthiness of its customers;
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the level of its operating and maintenance costs;
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damages to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters or acts of terrorism;
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outages in its pipeline systems or at its processing facilities;
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the relationship between natural gas and NGL prices and resulting effect on processing margins;
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leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise; and
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prevailing economic conditions.
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In addition, the actual amount of cash TEP will have available for distribution depends on other factors, including:
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the level and timing of capital expenditures TEP makes;
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the level of its general and administrative expenses, including reimbursements to its general partner and its affiliates, including Tallgrass Development, for services provided to TEP;
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the cost of pursuing and completing acquisitions, if any;
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its debt service requirements and other liabilities;
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fluctuations in its working capital needs;
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its ability to borrow funds and access capital markets;
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restrictions contained in its debt agreements;
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the amount of cash reserves established by its general partner; and
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other business risks affecting its cash levels.
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If TEP is not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, its financial condition, results of operation, cash flows and ability to make cash distributions to its unitholders will be adversely affected. With respect to its natural gas transportation and logistics segment, TEP has experienced decreases in revenues as compared to historical periods resulting from decreased renewals of long-haul firm capacity contracts with off-system customers over the last few years. If this trend continues, its ability to make cash distributions to its unitholders may be materially impacted.
TEP transports, stores and processes a substantial majority of the natural gas and crude oil on its systems under long-term contracts with terms of various durations. For the year ended December 31, 2014, approximately 93% of its natural gas transportation and storage revenues were generated under firm transportation and storage contracts. As of December 31, 2014, the weighted average remaining life of its long-term (defined as more than one-year in duration) natural gas transportation contracts and natural gas storage contracts was approximately three years and seven years, respectively, the weighted average remaining life of its oil transportation contracts was approximately five years, and the weighted average remaining life of its natural gas processing contracts was approximately three years. As these contracts expire, TEP may be unable to obtain new contracts on terms similar to those of its existing contracts, or at all. If TEP is unable to promptly resell capacity from expiring contracts on equivalent terms, its revenues may decrease and its ability to make cash distributions to its unitholders may be materially impaired.
For example, over the past several years, a number of TEP’s natural gas transportation and storage customers have opted not to renew their contracts for service on the TIGT System. TEP believes those non-renewals have been caused both by increased competition from large diameter long-haul pipeline systems that are more efficient and cost effective at transporting natural gas over long distances, as well as reduced drilling activity for dry gas in the Rocky Mountain region. These former customers are generally large producers that primarily used the TIGT System to access interstate pipelines for ultimate delivery to consuming markets outside TEP’s areas of operations, as opposed to TEP’s current customer base, which is primarily comprised of on-system regional customers, such as LDCs. The non-renewal of these transportation contracts has resulted in decreases in firm contracted capacity on the TIGT System and related decreases in total revenue. For example, TIGT’s average firm contracted capacity decreased from 842 MMcf/d for the year ended December 31, 2010 to 639 MMcf/d for the year ended December 31, 2014 and transportation services revenue decreased from $143.4 million to $102.0 million over the same period, primarily due to the loss of revenue from the non-renewal of transportation contracts.
TEP also may be unable to maintain the long-term nature and economic structure of its current contract portfolio over time. Depending on prevailing market conditions at the time of a contract renewal, transportation, storage and processing customers with fee-based contracts may desire to enter into contracts under different fee arrangements, and its potential customers may be generally unwilling to enter into long-term contracts. To the extent TEP is unable to renew or replace its existing contracts on terms that are favorable to it or successfully manage the long-term nature and economic structure of its contract profile over time, its revenues and cash flows could decline and its ability to make distributions to its unitholders could be materially and adversely affected. In addition, if an existing customer terminates or breaches its long-term firm transportation, storage or processing contract, TEP may be subject to a loss of revenue if TEP is unable to promptly resell the capacity to another customer on substantially equivalent terms.
TEP’s ability to renew or replace its expiring contracts on terms similar to, or more attractive than, those of its existing contracts is uncertain and depends on a number of factors beyond its control, including:
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the level of existing and new competition to provide transportation, storage and processing services to its markets;
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the macroeconomic factors affecting crude oil and natural gas gathering economics for its current and potential customers;
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the balance of supply and demand for natural gas and crude oil, on a short-term, seasonal and long-term basis, in the markets it serves;
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the extent to which the customers in its markets are willing to contract on a long-term basis; and
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the effects of federal, state or local laws or regulations on the contracting practices of its customers.
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As a result of the acquisition of an interest in Pony Express, TEP is engaged in crude oil transportation, which is a new line of business for TEP. TEP cannot provide assurance that its expansion into this line of business will succeed.
In September 2014, TEP acquired a 33.3% membership interest in Pony Express, which owns the Pony Express System, an approximately 698 mile crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma, with delivery points at Ponca City Refinery and Deeprock Development in Cushing. In March 2015, TEP acquired an additional 33.3% membership interest in Pony Express, resulting in TEP owning a 66.7% membership interest in Pony Express. In addition, upon completion of ongoing construction, the Pony Express System will also include an approximately 66-mile lateral in northeast Colorado that will commence in Weld County, Colorado and interconnect with the Pony Express System just east of Sterling, Colorado. The construction of the lateral in Northeast Colorado and its expected in-service date may be delayed, which could negatively impact its future financial performance and results of operations. Additionally, TEP shares joint tariffs with third-party pipelines delivering oil from the Bakken into Guernsey, Wyoming, and those pipelines are currently experiencing delays in their construction and expansion efforts, the continuance of which would further delay its ability to utilize the Pony Express System at full capacity, which in turn could negatively impact its financial performance and results of operations.
The ownership and operation of a crude oil pipeline is a new line of business for TEP, as its operations were previously focused on the transportation, storage and processing of natural gas. Operating a crude oil pipeline system requires different operating strategies and different managerial expertise than its current operations, and a crude oil pipeline system is subject to additional or different regulations. Failure to timely and successfully develop this new line of business in conjunction with its existing operations may have a material adverse effect on its business, financial condition and results of operations.
Increased competition from other companies that provide natural gas transportation, storage and processing and crude oil transportation services, or from alternative fuel sources, could have a negative impact on the demand for TEP’s services, which could materially and adversely affect its financial results.
TEP’s ability to renew or replace its existing contracts at rates sufficient to maintain current revenues and current cash flows could be adversely affected by the activities of its competitors. Some of TEP’s competitors have greater financial, managerial and other resources than TEP does and control substantially more transportation, storage and processing capacity and/or crude oil transportation capacity than TEP does. In addition, some of TEP’s competitors have assets in closer proximity to natural gas and/or crude oil supplies and have available idle capacity in existing assets that would not require new capital investments for use. For example, several pipelines access many of the same basins as TEP’s natural gas pipeline systems and transport gas to customers in the Rocky Mountain and Midwest regions of the United States. Pony Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and marketers looking to capitalize on basis differentials between two primary crude oil benchmarks (West Texas Intermediate Crude and Brent Crude). In addition, numerous other crude oil pipeline projects have been announced recently that would compete directly with TEP’s Pony Express crude oil pipeline system. TEP’s competitors may expand or construct new transportation, storage or processing systems that would create additional competition for the services TEP provides to its customers, or its customers may develop their own transportation, storage and processing facilities in lieu of using ours. The potential for the construction of new processing facilities in TEP’s areas of operation is particularly acute due to the nature of the processing industry and the attractive drilling profile of geographic areas served by its Midstream Facilities. Furthermore, Tallgrass Development and its affiliates are not limited in their ability to compete with TEP.
If TEP’s competitors were to substantially decrease the prices at which they offer their services, TEP may be unable to compete effectively and its cash flows and ability to make distributions to its unitholders may be materially impaired.
Further, natural gas as a fuel, and fuels derived from crude oil, compete with other forms of energy available to users, including electricity, coal and other liquid fuels. Increased demand for such forms of energy at the expense of natural gas or fuels derived from crude oil could lead to a reduction in demand for its services.
All of these competitive pressures could make it more difficult for TEP to renew its existing long-term, firm transportation, storage and processing contracts when they expire or to attract new customers as TEP seeks to expand its business, which could have a material adverse effect on its business, financial condition, results of operations and prospects. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas and crude oil in the markets TEP serves, 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 or crude oil.
If TEP is unable to make acquisitions on economically acceptable terms from Tallgrass Development or third parties, its future growth will be limited, and the acquisitions TEP does make may reduce, rather than increase, its cash generated from operations on a per unit basis.
TEP’s ability to grow depends, in part, on its ability to make acquisitions that increase its cash generated from operations on a per unit basis. The acquisition component of its strategy is based, in large part, on its expectation of ongoing divestitures of midstream energy assets by industry participants, including Tallgrass Development. Other than Tallgrass Development’s obligation to offer TEP certain assets (if Tallgrass Development decides to sell such assets) pursuant to the right of first offer under TEP's Omnibus Agreement, TEP has no contractual arrangement with Tallgrass Development that would require it to provide TEP with an opportunity to acquire midstream assets that it may sell. Accordingly, while TEP believes Tallgrass Development will be incentivized pursuant to its economic relationship with TEP to offer TEP opportunities to purchase midstream assets, there can be no assurance that any such offer will be made, and there can be no assurance TEP will reach agreement on the terms with respect to any acquisition opportunities offered to TEP by Tallgrass Development. Furthermore, many factors could impair its access to future midstream assets, including a change in control of Tallgrass Development or a transfer of the IDRs by its general partner to a third party. A material decrease in divestitures of midstream energy assets from Tallgrass Development or otherwise would limit its opportunities for future acquisitions and could have a material adverse effect on its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.
TEP’s future growth and ability to increase distributions will be limited if TEP is unable to make accretive acquisitions from Tallgrass Development or third parties because, among other reasons, (i) Tallgrass Development elects not to sell or contribute additional assets to TEP or to offer acquisition opportunities to TEP, (ii) TEP is unable to identify attractive third-party acquisition opportunities, (iii) TEP is unable to negotiate acceptable purchase contracts with Tallgrass Development or third parties, (iv) TEP is unable to obtain financing for these acquisitions on economically acceptable terms, (v) TEP is outbid by competitors or (vi) TEP is unable to obtain necessary governmental or third-party consents. Furthermore, even if TEP does make acquisitions that TEP believes 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:
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mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;
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an inability to maintain or secure adequate customer commitments to use the acquired systems or facilities;
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an inability to integrate successfully the assets or businesses TEP acquires;
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the assumption of unknown liabilities for which TEP is not indemnified or for which its indemnity is inadequate;
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the diversion of management’s and employees’ attention from other business concerns;
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unforeseen difficulties operating in new geographic areas or business lines; and
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a decrease in liquidity and increased leverage as a result of using significant amounts of available cash or debt to finance an acquisition.
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If any acquisition eventually proves not to be accretive to TEP’s distributable cash flow per unit, it could have a material adverse effect on its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.
If TEP is unable to obtain needed capital or financing on satisfactory terms to fund expansions of its asset base, its ability to make quarterly cash distributions may be diminished or its financial leverage could increase.
In order to expand its asset base through acquisitions or capital projects, TEP may need to make expansion capital expenditures. If TEP does not make sufficient or effective expansion capital expenditures, TEP will be unable to expand its business operations and may be unable to maintain or raise the level of its quarterly cash distributions. TEP could be required to use cash from its operations or incur borrowings or sell additional common units or other limited partner interests in order to fund its expansion capital expenditures. Using cash from operations will reduce cash available for distribution to its common unitholders. TEP’s ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by its financial condition at the time of any such financing or offering as well as the covenants in its debt agreements,
general economic conditions and contingencies and uncertainties that are beyond its control. Even if TEP is successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit its ability to pay distributions to its common unitholders. In addition, incurring additional debt may significantly increase its 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 its ability to pay distributions at the then-current distribution rate.
TEP does not currently have any commitment with its general partner or other affiliates, including Tallgrass Development, to provide any direct or indirect financial assistance to TEP.
TEP is exposed to direct commodity price risk with respect to some of its processing revenues, and its exposure to direct commodity price risk may increase in the future.
TEP’s Processing & Logistics segment operates under three types of contracts, two of which directly expose its cash flows to increases and decreases in the price of natural gas and NGLs: percent of proceeds and keep whole processing contracts. As of December 31, 2014, approximately 13% of the reserved capacity in its Processing & Logistics segment was contracted under percent of proceeds or keep whole processing contracts. TEP does not currently hedge the commodity exposure inherent in these types of processing contracts due to the minimal impact to TEP’s overall financial condition and results of operations, and as a result, its revenues and results of operations are impacted by fluctuations in the prices of natural gas and NGLs.
Percent of proceeds processing contracts generally provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under keep whole processing contracts, TEP’s revenues and cash flows generally increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect its profitability. When natural gas prices are low relative to NGL prices, it is more profitable for TEP to process natural gas under keep whole arrangements. When natural gas prices are high relative to NGL prices, it is less profitable for TEP and its customers to process natural gas both because of the higher value of natural gas and the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, TEP may experience periods in which higher natural gas prices relative to NGL prices reduce its processing margins or reduce the volume of natural gas processed at some of its plants. In addition, NGL prices have historically been related to the market price of oil and as a result any significant changes in oil prices could also indirectly impact its operations. Indirectly, reduced commodity prices impact TEP through reduced exploration and production activity, which results in fewer opportunities for new business to offset potential volume declines. NGL and natural gas prices are impacted by changes in the supply and demand for NGLs and natural gas. In the latter half of 2014 and the beginning of 2015, natural gas prices have declined substantially and such declines may result in lower realizations on our percent of proceeds and keep whole processing contracts.
If third-party pipelines or other midstream facilities interconnected to its systems become partially or fully unavailable, or if the volumes TEP transports do not meet the quality requirements of such pipelines or facilities, its revenues and its ability to make distributions to its unitholders could be adversely affected.
TEP’s natural gas transportation, storage and processing facilities and its oil transportation facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties, such as Phillips 66, Deeprock Development, LLC and others. For example, a substantial majority of the NGLs TEP processes are transported on the Powder River pipeline owned by Phillips 66, and therefore, any downtime on this pipeline as a result of maintenance or force majeure would adversely affect TEP. For example, its Pony Express System connects to upstream joint tariff pipelines, including the Belle Fourche Pipeline owned by the True Companies (which also own and operate the Bridger Pipeline) and Hiland Double H Pipeline, which are responsible for delivering a substantial portion of the crude oil for transportation on the Pony Express System. Plus, nearly all of the crude oil TEP transports on the Pony Express System is stored in crude oil tanks located on or pumped over to downstream pipelines that interconnect through the Deeprock Development terminal facility in Cushing, Oklahoma. The continuing operation of such third- party pipelines, processing plants, crude oil terminal facilities and other midstream facilities is not within its control. These pipelines, plants and other midstream facilities may become unavailable to TEP for any number of reasons, including because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from weather events or other operational hazards. For example, the operations of the Bridger Pipeline’s Poplar System are down indefinitely due to an apparent pipeline release on or about January 21, 2015. Bridger has declared a Force Majeure as a result of this event and has indicated that it does not have the capacity to make up volumes on other lines that directly or indirectly deliver crude oil into designated origin points on the Pony Express System or the Belle Fourche Pipeline. The largest committed shipper on the Pony Express System has also declared a force majeure as a result of this incident. TEP is currently evaluating the impact this will have on the operations of its Pony Express System, but it could result in decreased transportation throughput, increased costs and reduced revenues.
In addition, if the costs to TEP to access and transport on these third-party pipelines significantly increase, its profitability could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive, transport or process natural gas or to store or transport crude oil, or if the volumes TEP transports or process do not meet the quality requirements of such pipelines or facilities, its revenues and its ability to make quarterly cash distributions to its unitholders could be adversely affected. For example, in May 2014 Phillips 66 notified TEP of an allegation that Tallgrass Midstream, LLC (“Tallgrass Midstream”) had been delivering NGLs to the Powder River NGL pipeline with methanol levels in excess of applicable tolerances. The Douglas plant was shut in completely for five days, and operated at approximately 50% of its processing capacity for another 10 days, as a result. Although Tallgrass Midstream was reimbursed by its upstream suppliers for substantially all of the off-spec fees imposed by Phillips 66 during 2014, Phillips 66 could also attempt to seek payment for any other costs (including those associated with overtime, testing, and shipping), penalties or damages allegedly incurred by them in connection with their processing, use or sale of the NGLs. If TEP is required to make additional substantial payments to Phillips 66 for costs, penalties or other damages and are unable to recover such amounts from upstream suppliers, its revenues and ability to make distributions to unitholders could be adversely affected.
The revenue in TEP’s Processing and Logistics segment largely depends on the amount of natural gas that its customers actually deliver to its natural gas processing plants.
As of December 31, 2014, approximately 87% of its reserved capacity at its Casper and Douglas natural gas processing plants was subject to fee-based processing contracts (the remaining 13% was subject to percent of proceeds or keep whole processing contracts). On these fee-based contracts, TEP’s revenue is largely tied to the amount of natural gas that its customers actually deliver its Casper and Douglas plants for processing. Unlike many pipeline transportation customers, TEP’s natural gas processing customers are not generally subject to “take or pay” obligations. Thus, if its natural gas processing customers do not produce natural gas and deliver that natural gas to its processing plants to be processed, revenue for its Processing and Logistics Segment will decline. If natural gas, crude oil or NGL prices decline, as has been the case over the latter half of 2014 and the first part of 2015, TEP’s customers may make less money from the production of natural gas, crude oil or NGLs than it costs them to produce it. If that happens, its customers may not continue to produce natural gas and its revenue will decline. In addition, the fees its customers pay to reserve capacity at its processing plants may not deter those customers from processing their natural gas volumes at other facilities, with whom they may have had prior arrangements or otherwise.
Any significant decrease in available supplies of natural gas or crude oil in TEP’s areas of operation, or redirection of existing natural gas or crude oil supplies to other markets, could adversely affect its business and operating results. If recent lower commodity prices for oil and gas are prolonged beyond our contract lives, we may experience lower throughput volumes and reduced cash flows.
TEP’s business is dependent on the continued availability of natural gas and crude oil production and reserves. Production from existing wells and natural gas and crude oil supply basins with access to its transportation, storage and processing facilities will naturally decline over time. The amount of natural gas and crude oil 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. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas and crude oil transported and natural gas stored and processed on its systems and cash flows associated therewith, its customers must continually obtain adequate supplies of natural gas and crude oil.
However, the development of additional natural gas and crude oil reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, storage, transportation and other facilities that permit natural gas and crude oil to be produced and delivered to its transportation, storage and processing facilities. In addition, low prices for natural gas and crude oil, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could have a material adverse effect on the development and production of additional reserves, as well as storage, pipeline transportation, and import and export of natural gas and crude oil supplies. A period of sustained price reductions in crude oil or refined products could lead to a decline in drilling activity, production and refining of crude oil, or import levels in these areas. For example, in response to recent declines in crude oil prices, a number of producers in TEP’s areas of operation have announced significant reductions in their capital budget and drilling plans for 2015. In addition, production may fluctuate for other reasons, including, for example, in the case of crude oil, the decisions made by the members of the Organization of the Petroleum Exporting Countries (“OPEC”), regarding production controls. Furthermore, competition for natural gas and crude oil supplies to serve other markets could reduce the amount of natural gas and crude oil supply available for its customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas and crude oil transported on TEP’s systems and cash flows associated with its operations, its customers must compete with others to obtain adequate supplies of natural gas and crude oil.
If new supplies of natural gas and crude oil are not obtained to replace the natural decline in volumes from existing supply basins, if natural gas and crude oil supplies are diverted to serve other markets, if environmental regulations restrict new natural gas and crude oil drilling or if OPEC does not agree to and maintain production controls, the overall demand for transportation, storage and processing services on its systems may decline, which could have a material adverse effect on its ability to renew or replace its current customer contracts when they expire and on its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.
TEP’s natural gas and crude oil operations 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 its business, financial condition, and results of operations.
TEP provides open-access interstate transportation service on its natural gas transportation systems pursuant to tariffs approved by the FERC. TEP’s natural gas transportation and storage operations are regulated by the FERC, under the Natural Gas Act of 1938 (the “NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”), and the Energy Policy Act of 2005 (the “EPAct”). The TIGT System and the Trailblazer Pipeline each operates under a tariff approved by the FERC that establishes rates, cost recovery mechanisms and terms and conditions of service to its customers. The rates and terms of service on the Pony Express System are subject to regulation by the FERC under the Interstate Commerce Act (the “ICA”) and the Energy Policy Act of 1992. TEP provides interstate transportation service on the Pony Express System pursuant to tariffs on file with the FERC.
Generally, the FERC’s authority over natural gas facilities extends to:
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rates, operating terms and conditions of service;
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the form of tariffs governing service;
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the types of services TEP may offer to its customers;
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the certification and construction of new, or the expansion of existing, facilities;
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the acquisition, extension, disposition or abandonment of facilities;
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creditworthiness and credit support requirements;
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the maintenance of accounts and records;
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relationships among affiliated companies involved in certain aspects of the natural gas business;
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depreciation and amortization policies; and
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the initiation and discontinuation of services.
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The FERC’s authority over crude oil pipelines is less broad, extending to:
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rates, operating terms and conditions of service;
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the form of tariffs governing service;
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the maintenance of accounts and records;
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relationships among affiliated transporters and shippers; and
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depreciation and amortization policies.
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Interstate natural gas pipelines subject to the jurisdiction of the FERC may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust, unreasonable, unduly discriminatory, or preferential. The maximum recourse rate that TEP may charge for its natural gas transportation 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 its FERC-approved tariff.
Pursuant to the NGA, existing interstate natural gas 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. TEP currently holds authority from the FERC to charge and collect (i) “recourse rates” (i.e., the maximum cost-based rates an interstate natural gas pipeline may charge for its services under its tariff); (ii) “discount rates” (i.e., rates offered by the natural gas pipeline to shippers at discounts vis-à-vis the recourse rates and that fall within the cost-based maximum and minimum rate levels set forth in the natural gas pipeline’s tariff); and (iii) “negotiated rates” (i.e., rates negotiated and agreed to by the pipeline and the shipper for the contract term that may fall within or outside of the cost-based maximum and minimum rate levels set forth in the tariff, and which are individually filed
with the FERC for review and acceptance). When capacity is available and offered for sale, the rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) at which such capacity is sold are subject to regulatory approval and oversight. Regulators and customers on its natural gas pipeline systems have the right to protest or otherwise challenge the rates that TEP charges under a process prescribed by applicable regulations. The FERC may also initiate reviews of its rates. Customers on TEP’s natural gas pipeline systems may also dispute terms and conditions contained in its agreements, as well as the interpretation and application of its tariffs, among other things.
Rates for crude oil transportation service must be filed as a tariff with the FERC and are subject to applicable FERC regulation. The filed tariff rates include contract rates entered into with shippers willing to make long term commitments to the pipeline to support new pipeline capacity and “walk-up” rates available to uncommitted non-contract shippers. Crude oil pipelines typically must reserve at least ten percent of their capacity for walk-up shippers. Crude oil pipeline tariff rates may be adjusted, positively or negatively, on an annual basis through a FERC indexing procedure. A crude oil pipeline may also file new tariff rates at any time, subject to shipper contract restrictions and FERC regulatory procedures. The filing of any indexed rate increase or other rate increase may be protested and subjected to cost-of-service review by the FERC to determine whether the proposed new rate is just and reasonable.
Under the ICA, which applies to FERC-regulated liquids pipelines such as the Pony Express System, parties having standing may challenge new or existing rates and terms and conditions of service at any time. The FERC is authorized to suspend, subject to refund, the effectiveness of a protested rate for up to seven months while it determines if the protested rate is just and reasonable. TEP’s rates may be reduced and TEP may be required to issue refunds as a result of settlement or by an order of the FERC following a hearing finding that a protested rate is unjust and unreasonable. If the complaint is not resolved by settlement, the FERC may conduct a hearing and order the crude oil pipeline to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. TEP cannot guarantee that any new or existing rate on the Pony Express System would not be rejected or modified by the FERC, or subjected to refunds or reparations. While the FERC regulates rates and terms and conditions of service for transportation of crude oil in interstate commerce by pipeline, state agencies may also regulate facilities (including construction, acquisition, disposition, financing, and abandonment), rates, and terms and conditions of service for crude oil pipeline transportation in intrastate commerce. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on its business, financial condition and results of operations.
The Trailblazer Pipeline, one of TEP’s interstate natural gas pipelines, uses two types of fuel to power its compressors: (1) natural gas and (2) electric power. For the natural gas compression, customers are charged a gas retainage percentage as an in-kind reimbursement for fuel. For the electric compression, customers are charged a commodity rate for the electricity used at the pipeline’s stations. The volume of gas and cost of electric power are tracked and adjusted in annual periodic rate adjustment filings made pursuant to the tariff. Lost and unaccounted for gas is also tracked and adjusted in annual periodic rate adjustment filings. These costs were subject to the NGA Section 4 rate case initiated by the Trailblazer Pipeline and resolved by settlement as approved by the FERC in May 2014. On TIGT, TEP’s gas compressor fuel costs and the cost of lost and unaccounted for gas (together referred to as “Fuel Retention Factors”) are recovered by retaining a fixed percentage of natural gas throughput on its transportation and storage facilities. These Fuel Retention Factors were the subject of a Section 5 proceeding initiated by the FERC that TEP resolved with customers by a settlement approved by the FERC in September 2011.
The FERC’s jurisdiction over natural gas facilities 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. With some exceptions applicable to smaller projects, auxiliary facilities, and certain facility replacements, prior to commencing construction and/or operation of new or existing interstate natural gas transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction from, or file to amend its existing certificate with, 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 delay or refusal by an agency to issue authorizations or permits as requested for one or more of these projects may mean that they will be constructed in a manner or with capital requirements that TEP did not anticipate or that TEP will not be able to pursue these projects. Such delay, modification or refusal could materially and negatively impact the additional revenues expected from these projects. The FERC does not regulate the construction, expansion, or abandonment of crude oil pipelines nor the initiation or discontinuation of services on those pipelines, provided that the action taken is not discriminatory or preferential among similarly situated shippers.
The FERC has the authority to conduct audits of regulated entities to assess compliance with FERC regulations and policies. The FERC also conducts audits to verify that the websites of interstate natural gas pipelines accurately provide information on the operations and availability of services on the pipeline. FERC regulations also require entities providing natural gas and crude oil transportation services to comply with uniform terms and conditions for service, as set forth in publicly available tariffs or, as it concerns natural gas facilities, agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are generally required to conform, in all material
respects, with the standard form of service agreements set forth in the natural gas pipeline’s FERC-approved tariff. The pipeline and a customer may choose to enter into a non-conforming service agreement so long as this agreement is 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, the FERC could reject the agreement or require TEP to modify the agreement, or alternatively require TEP to modify its tariff so that the non-conforming provisions are generally available to all customers. Agreements entered into with crude oil shippers are generally not available for public review, but the rates and terms and service provided to similarly situated shippers may not be unduly discriminatory or preferential.
The FERC has promulgated rules and policies covering many aspects of TEP’s natural gas pipeline business, including regulations that require TEP to provide firm and interruptible transportation service on an open access basis that is not unduly discriminatory or preferential, provide internet access to current information about its available pipeline capacity and other relevant transmission information, and permit pipeline shippers to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. FERC regulations also prevent interstate natural gas pipelines from sharing customer information with marketing affiliates, and restrict how interstate natural gas pipelines share transportation with marketing affiliates. FERC regulations require that certain transmission function personnel of interstate natural gas pipelines function independently of personnel engaged in natural gas marketing functions. Crude oil pipelines subject to the ICA must comply with FERC regulations that require the pipeline to act as a common carrier and not engage in undue discrimination or preferential treatment with respect to shippers.
FERC policies also govern how interstate natural gas pipelines respond to interconnection requests from third party facilities, including other pipelines. Generally, an interstate natural gas pipeline must grant an interconnection request upon the satisfaction of several conditions. As a consequence, an interstate natural gas pipeline faces the risk that an interconnecting third party pipeline may pose a risk of additional competition to serve a particular market. Failure to comply with applicable provisions of the NGA, NGPA, EPAct 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, including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of up to $1.0 million per day, per violation. Violations of the ICA, the Energy Policy Act of 1992, or regulations and orders promulgated by the FERC are also subject to administrative and criminal penalties and remedies, including forfeiture and individual liability.
In addition, new laws or regulations or different interpretations of existing laws or regulations applicable to TEP’s pipeline systems or midstream facilities could have a material adverse effect on its business, financial condition, results of operations and prospects. For example, 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. TEP may face challenges to its rates or terms of service in the future. Any successful challenge could materially adversely affect its future earnings and cash flows.
The rates of TEP’s regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.
TEP’s shippers or other interested stakeholders, such as state regulatory agencies, may challenge the rates or the terms and conditions of service applicable to its natural gas or crude oil pipeline tariffs, unless they have entered into agreements not to challenge such tariffs. The FERC has authority to investigate TEP’s rates and terms and conditions of service pursuant to NGA Section 5 for natural gas pipelines and the ICA for common carrier oil pipelines. TEP’s crude oil firm contract shippers have generally agreed not to complain or protest rates unless they are in conflict with their contracts. With regard to TEP’s natural gas pipelines, Trailblazer initiated on its own initiative, under NGA Section 4, a rate proceeding with the FERC on July 1, 2013 to implement a general rate increase to its recourse rates, initiate a rolled-in rate structure for expansion facilities certificated in 2001, and adopt miscellaneous other updates to its General Terms and Conditions in its tariff. On February 24, 2014, Trailblazer submitted to the FERC an uncontested offer of settlement and stipulation to resolve the proceeding by, among other things: (a) setting new maximum recourse rates based upon a “black box” cost of service of $21.1 million, (b) revising the charges and methods for recovery of fuel (natural gas and electric power used in providing service) costs, (c) providing for revenue sharing of certain interruptible and short-term firm service revenues with eligible maximum recourse rate firm service shippers, (d) establishing a rate moratorium until January 1, 2016, and (e) requiring a general rate case to be filed no later than January 1, 2019. The FERC accepted the settlement agreement by letter order on May 29, 2014. Per the terms of the settlement, Trailblazer is required to file a new general rate case by January 1, 2019, and no customer or participant who joined the settlement (defined in the settlement as a “Settling Party”) may file to change the settlement rates before January 1, 2016. TIGT is not subject to any current moratorium on complaints or protests regarding its rates or terms and conditions of service. The rates on TEP’s TIGT natural gas pipeline system were subject to a NGA Section 5 proceeding initiated by the FERC relating to TIGT’s Fuel Retention Factors, which generally are recovered by retaining a fixed percentage of natural gas throughput on TIGT’s natural gas transportation and storage facilities. TIGT resolved these issues with customers by a settlement approved by the FERC in September 2011, which resulted in a 27% reduction in the Fuel Retention Factors billed to shippers effective
June 1, 2011. The Section 5 Settlement also provided for a second stepped reduction, resulting in a total 30% reduction in the Fuel Retention Factors billed to shippers and effective January 1, 2012, for certain segments of the former Pony Express natural gas pipeline system.
On TEP’s crude oil pipeline system, shippers may challenge new or existing rates at any time. As a result of settlement or by order of the FERC following hearing, its rates may be reduced. If a shipper files a complaint, and if the complaint is not resolved with that shipper, to the extent the FERC determines after hearing that TEP has collected payment on rates not previously found to be just and reasonable, TEP may be required to pay reparations to that shipper for up to two years prior to the date on which a complaint was filed. Regardless of the prospective just and reasonable rate, reparations may not be required below the last rates determined by the FERC to be just and reasonable. In other words, crude oil pipelines are not required to make reparations that refund revenues collected pursuant to rates previously determined to be just and reasonable.
Successful challenges to rates charged on TEP’s natural gas and crude oil pipeline systems, or to the terms and conditions of service on those systems, could have a material adverse effect on its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.
TEP is exposed to the creditworthiness and performance of its customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect its financial condition, cash flows, and operating results.
Although TEP attempts to assess the creditworthiness of its customers, suppliers and contract counterparties, there can be no assurance that its assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on its business, results of operations, financial condition and ability to make cash distributions to its unitholders. In addition, TEP’s long-term firm transportation and storage contracts obligate its customers to pay demand charges regardless of whether they transport or store natural gas or crude oil on its facilities, except for certain circumstances when TEP is unable to schedule the customer’s nomination for service. As a result, during the term of TEP’s long-term firm transportation and storage contracts and absent an event of force majeure, its revenues will generally depend on its customers’ financial condition and their ability to pay rather than upon the amount of natural gas or crude oil transported. Further, its contract counterparties may not perform or adhere to its existing or future contractual arrangements. Any material nonpayment or nonperformance by its contract counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could have an adverse impact on its business, results of operations, financial condition and ability to make cash distributions to its unitholders.
The procedures and policies TEP uses to manage its exposure to credit risk, such as credit analysis, credit monitoring and, in some cases, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent its procedures and policies prove to be inadequate, its financial and operational results may be negatively impacted. Some of TEP’s counterparties may be highly leveraged or have limited financial resources and are subject to their own operating and regulatory risks. Even if its credit review and analysis mechanisms work properly, TEP may experience financial losses in its dealings with such parties. As seen with the recent decline in crude oil prices, prices for crude oil and natural gas are subject to large fluctuations in response to relatively minor changes in supply and demand, market uncertainty and a variety of other factors that are beyond its control. Such volatility in commodity prices might have an impact on many of its counterparties and their ability to borrow and obtain additional capital on attractive terms, which, in turn, could have a negative impact on their ability to meet their obligations to TEP and may also increase the magnitude of these obligations.
Any material nonpayment or nonperformance by its counterparties could require TEP to pursue substitute counterparties for the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.
Constructing new assets subjects TEP to risks of project delays, cost overruns and lower-than-anticipated volumes of natural gas or crude oil once a project is completed. TEP’s operating cash flows from its capital projects may not be immediate or meet its expectations.
One of the ways TEP may grow its business is by constructing additions or modifications to its existing facilities. TEP also may construct new facilities, either near its existing operations or in new areas. For example, in 2013 TEP completed an expansion of its Casper and Douglas plants to increase processing capacity and upgrade compression. Pony Express substantially completed its approximately 698-mile crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma during 2014 and is currently constructing an approximately 66-mile lateral in Northeast Colorado. Construction projects require significant amounts of capital and involve numerous regulatory, environmental, political, legal and operational uncertainties, many of which are beyond its control. These projects also involve numerous economic uncertainties, including the impact of inflation on project costs and the availability of required resources.
TEP may be unable to complete announced construction projects, including the potential expansion of the Pony Express System announced in its public filings, on schedule, at the budgeted cost, or at all, which could have a material adverse effect
on its business and results of operations. Moreover, TEP may not receive any material increase in operating cash flow from a project for some time. For instance, if TEP expands a pipeline or processing facility, the construction expenditures may occur over an extended period of time, yet TEP will not receive any material increases in cash flow until the project is completed and fully operational. In addition, its cash flow from a project may be delayed or may not meet its expectations. TEP’s project specifications and expectations regarding project cost, timing, asset performance, investment returns and other matters usually rely in part on the expertise of third parties such as engineers, technical experts and construction contractors. These estimates may prove to be inaccurate because of numerous operational, technological, economic and other uncertainties.
TEP relies in part on estimates from producers regarding the timing and volume of anticipated natural gas and crude oil production. Production estimates are subject to numerous uncertainties, all of which are beyond its control. These estimates may prove to be inaccurate, and new facilities may not attract sufficient volumes to achieve its expected cash flow and investment return.
TEP’s success depends on the supply and demand for natural gas and crude oil.
The success of its business is in many ways impacted by the supply and demand for natural gas and crude oil. For example, TEP’s business can be negatively impacted by sustained downturns in supply and demand for natural gas and crude oil in the markets that TEP serves, including reductions in its ability to renew contracts on favorable terms and to construct new infrastructure. One of the major factors that will impact natural gas demand will be the potential growth of the demand for natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation. One of the major factors impacting domestic natural gas and crude oil supplies has been the significant growth in unconventional sources such as shale plays and the continued progression of hydraulic fracturing technology. The supply and demand for natural gas and crude oil, and therefore the future rate of growth of its business, depends on these and many other factors outside of its control, including, but not limited to:
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adverse changes in general global economic conditions;
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adverse changes in domestic regulations;
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technological advancements that may drive further increases in production and reduction in costs of developing natural gas shales;
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the price and availability of other forms of energy;
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prices for natural gas, crude oil and NGLs;
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decisions of the members of the OPEC regarding price and production controls;
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increased costs to explore for, develop, produce, gather, process and transport natural gas or to transport crude oil;
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weather conditions, seasonal trends and hurricane disruptions;
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the nature and extent of, and changes in, governmental regulation, for example greenhouse gas legislation, taxation and hydraulic fracturing;
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perceptions of customers on the availability and price volatility of its services and natural gas and crude oil prices, particularly customers’ perceptions on the volatility of natural gas and crude oil prices over the long term;
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capacity and transportation service into, or out of, its markets; and
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petrochemical demand for NGLs.
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TEP is subject to numerous hazards and operational risks.
TEP’s operations are subject to all the risks and hazards typically associated with transportation, storage and processing of natural gas and the transportation of crude oil. These operating risks include, but are not limited to:
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damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires or other adverse weather conditions and other natural disasters and acts of terrorism;
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inadvertent damage from construction, vehicles, farm and utility equipment;
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uncontrolled releases of crude oil, natural gas and other hydrocarbons;
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leaks, migrations or losses of natural gas and crude oil as a result of the malfunction of equipment or facilities;
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outages at its processing facilities;
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ruptures, fires, leaks and explosions; and
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other hazards that could also result in personal injury and loss of life, pollution and other environmental risks, and suspension of operations.
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For example, failures occurred on two separate pipeline segments of the TIGT System during 2013; one in Kimball County, Nebraska on May 4, 2013 and one in Goshen County, Wyoming on June 13, 2013. The failures both resulted in the release of natural gas. Both lines were promptly brought back into service and neither failure caused any known injuries, fatalities, fires or evacuations. The costs to repair or replace the damaged section in Kimball County, Nebraska were not material. In February 2014, TEP communicated to PHMSA that TEP’s investigation of the pipeline involved in the Kimball County failure is complete. TEP has since placed this line into oil service and restored pressure to full maximum allowable operating pressure. TEP is currently working with PHMSA to develop a plan to close the Corrective Action Order received from PHMSA regarding the Goshen County failure and is evaluating the cost of anticipated remediation activities.
TEP has also had four minor incidents on the Pony Express System that TEP reported to PHMSA during final commissioning and since the line has been placed into commercial service. On August 31, 2014 a leak occurred at the Sterling Pump Station in Logan County, Colorado, which resulted in a release of approximately 200 bbls of crude oil. The spill was entirely contained on Tallgrass property. On October 7, 2014 an overpressure event occurred upstream of the Lincoln Pump Station, which resulted in an overflow of the sump at the Lincoln Pump Station. On October 28, 2014, an overpressure situation occurred at the Cushing Terminal in Payne County, Oklahoma. On November 17, 2014, a leak occurred at the Sterling Pig Adapter in Logan County, Colorado due to a one inch valve that was inadvertently left in a partial open state. This incident resulted in a spill of approximately 119 bbls of crude oil. The Pony Express System is a newly commissioned crude oil pipeline and these integrity issues may continue for the foreseeable future.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of certain segments of TEP’s pipeline systems in or near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas could increase the level of damages resulting from these risks. Despite the precautions TEP takes, events such as those described above could cause considerable harm to people or property, could result in loss of service available to customers, and could have a material adverse effect on its financial condition and results of operations and ability to make distributions to unitholders. In addition, maintenance, repair and remediation activities could result in service interruptions on segments of its systems or alter the operational profile of its systems. Potential impacts arising from these service interruptions or operational profile changes on segments of TEP’s systems could include, among others, limitations on its ability to satisfy customer requirements, obligations to provide reservation charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new projects that would compete directly with existing services.
TEP could be required by regulatory authorities to test or undertake modifications to its systems, operations or both that could result in a material adverse impact on its business, financial condition and results of operations. For example, TEP received a Corrective Action Order from PHMSA on June 19, 2013 directing TEP to take certain investigative, testing and corrective measures with regard to the segment of the TIGT pipeline that failed on June 13, 2013. Such actions, including those required by PHMSA, could materially and adversely impact its ability to meet contractual obligations and retain customers, with a resulting material adverse impact on its business and results of operations, and could also limit or prevent its ability to make quarterly cash distributions to its unitholders. Some or all of its costs arising from these operational risks may not be recoverable under insurance, contractual indemnification or increases in rates charged to its customers.
TEP’s insurance coverage may not be adequate.
TEP is not insured or fully insured against all risks that could affect its business, including losses from environmental accidents. For example, TEP does not maintain business interruption insurance in the type and amount to cover all possible losses. In addition, TEP does not carry insurance for certain environmental exposures, including but not limited to potential environmental fines and penalties, certain business interruptions, named windstorm or hurricane exposures and, in limited circumstances, certain political risk exposures. Further, in the event there is a total or partial loss of one or more of its insured assets, any insurance proceeds that TEP may receive in respect thereof may be insufficient to effect a restoration of such asset to the condition that existed prior to such loss. In addition, TEP is either not insured or not fully insured with respect to the legal proceedings described in Note 12
- Legal and Environmental Matters
to the condensed combined financial statements included herein and may, depending upon the circumstances, need to pay self-insured retention amounts prior to having losses covered by the insurance providers. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on its business, financial condition, results of operations and cash flows.
Furthermore, TEP may not be able to maintain or obtain insurance of the type and amount it desires at reasonable rates, and it may elect to self-insure all or a portion of TEP’s risks of loss. As a result of market conditions, premiums and deductibles for certain types of insurance policies may substantially increase, and in some instances, certain types of insurance could become unavailable or available only for reduced amounts of coverage. Any insurance coverage TEP does obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses.
TEP’s pipeline integrity program may impose significant costs and liabilities on TEP, while increased regulatory requirements relating to the integrity of its pipeline systems may require TEP to make additional capital and operating expenditures to comply with such requirements.
TEP is subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal requirements set by PHMSA for owners and operators of natural gas and crude oil pipelines in the areas of pipeline design, construction, and testing, the qualification of personnel and the development of operations and emergency response plans. The rules require pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments located in what the rules refer to as High Consequence Areas (“HCAs”).
Its pipeline operations are subject to pipeline safety regulations administered by PHMSA. These regulations, among other things, include requirements to monitor and maintain the integrity of its pipeline systems and determine the pressures at which its pipeline systems can operate. The Pipeline Safety Act of 2011 enacted January 3, 2012, amends the Pipeline Safety Improvement Act of 2002, or the Pipeline Safety Act of 2002, in a number of significant ways, including:
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reauthorizing funding for federal pipeline safety programs, increasing penalties for safety violations and establishing additional safety requirements for newly constructed pipelines;
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requiring PHMSA to adopt appropriate regulations within two years and requiring the use of automatic or remote- controlled shutoff valves on new or rebuilt pipeline facilities;
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requiring operators of pipelines to verify maximum allowable operating pressure and report exceedances within five days; and
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requiring studies of certain safety issues that could result in the adoption of new regulatory requirements for new and existing pipelines, including changes to integrity management requirements for HCAs, and expansion of those requirements to areas outside of HCAs.
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PHMSA published an advanced notice of proposed rule making in August 2011 to solicit comments on the need for changes to its safety regulations, including whether to revise integrity management requirements. On August 13, 2012, PHMSA published rules to update pipeline safety regulations to reflect provisions included in the Pipeline Safety Act of 2011, including increasing maximum civil penalties from $0.1 million to $0.2 million per violation per day of violation and from $1.0 million to $2.0 million as a maximum amount for a related series of violations as well as changing PHMSA’s enforcement process.
The ultimate costs of compliance with the integrity management rules are difficult to predict. The majority of the costs to comply with the rules are associated with pipeline integrity testing and the repairs found to be necessary. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs can have a significant impact on the costs to perform integrity testing and repairs. TEP is currently performing inspections on certain segments of the Trailblazer Pipeline that collectively total approximately 70-miles as part of TEP’s integrity management program to identify potential areas for replacement and repair. In connection with TEP’s acquisition of the Trailblazer Pipeline, Tallgrass Development agreed to contractually indemnify TEP for any out of pocket costs TEP incurs between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions are necessitated by external corrosion caused by the pipeline’s disbonded Hi-Melt CTE coating. The contractual indemnity provided to TEP by Tallgrass Development is capped at $20 million and is subject to TEP’s first paying an annual $1.5 million deductible. TEP may not be able to recover any or all of such out of pocket costs that are not covered by this contractual indemnity from its customers unless and until TEP receives FERC approval to recover such costs through a general rate increase or other FERC-approved recovery mechanism. TEP plans to continue its pipeline integrity testing programs to assess and maintain the integrity of its existing and future pipelines as required by the United States Department of Transportation rules. The results of these tests could cause TEP to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines, which expenditures could be material.
Further, additional laws, regulations and policies that may be enacted or adopted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. For example, PHMSA issued an Advisory Bulletin in May 2012 which advised pipeline operators that they must have records to document the maximum allowable operating pressure for each section of their pipeline and that the records must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities to meet the demands of verifiable pressures, could significantly increase TEP’s costs. TIGT continues to investigate and, when necessary, report to PHMSA the miles of pipeline for which it has incomplete records for Maximum Allowable Operating Pressure (“MAOP”). TEP is currently undertaking an extensive internal record review in view of the anticipated PHMSA annual reporting requirements. Additionally, failure to locate such records or verify maximum pressures could require TEP to operate at reduced pressures, which would reduce available capacity on its natural gas pipeline systems. These specific requirements do not currently apply to crude oil pipelines, but forthcoming
regulations implementing the Pipeline Safety Act of 2012 likely will expand the scope of regulation applicable to crude oil pipelines. There can be no assurance as to the amount or timing of future expenditures required to comply with pipeline integrity regulation, and actual future expenditures may be different from the amounts TEP currently anticipates. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on its business, financial position, results of operations and prospects. In addition, TEP may be subject to enforcement actions and penalties for failure to comply with pipeline regulations.
On August 29, 2012, PHMSA notified TIGT that a report from an audit conducted in 2010 indicated a probable violation for failing to perform a periodic review of personnel responses to certain abnormal operations. Specifically, PHMSA cited to the operation of a relief valve on March 3, 2010. TIGT responded to the notice of probable violation and requested a hearing in a response filed with PHMSA on October 1, 2012. A hearing was held on January 15, 2013 and a Final Order was received on October 30, 2013 that required TEP to modify its operating procedures to further address abnormal operating conditions. Failures occurred on two separate pipeline segments of the TIGT System during 2013; one in Kimball County, Nebraska on May 4, 2013 and one in Goshen County, Wyoming on June 13, 2013. The failures both resulted in the release of natural gas. Both lines were promptly brought back into service and neither failure caused any known injuries, fatalities, fires or evacuations. The costs to repair or replace the damaged section in Kimball County, Nebraska were not material. In February 2014, TEP communicated to PHMSA that TEP’s investigation of the pipeline involved in the Kimball County failure is complete. TEP has since placed this line into oil service and restored pressure to full maximum allowable operating pressure. TEP is currently working with PHMSA to develop a plan to close the Corrective Action Order received from PHMSA regarding the Goshen County failure and is evaluating the cost of anticipated remediation activities.
TEP has also had four minor incidents on the Pony Express System that TEP reported to PHMSA during final commissioning and since the line has been placed into commercial service. On August 31, 2014 a leak occurred at the Sterling Pump Station in Logan County, Colorado, which resulted in a release of approximately 200 bbls of crude oil. The spill was entirely contained on Tallgrass property. On October 7, 2014 an overpressure event occurred upstream of the Lincoln Pump Station, which resulted in an overflow of the sump at the Lincoln Pump Station. On October 28, 2014, an overpressure situation occurred at the Cushing Terminal in Payne County, Oklahoma. On November 17, 2014, a leak occurred at the Sterling Pig Adapter in Logan County, Colorado due to a one-inch valve that was left in a partial open state. This incident resulted in a spill of approximately 119 bbls of crude oil. The Pony Express System is a newly commissioned crude oil pipeline and these integrity issues may continue for the foreseeable future. There can be no assurance as to the amount or timing of future expenditures required to remediate or resolve these issues, and actual future expenditures may be different from the amounts TEP currently anticipates. These integrity issues could have a material adverse effect on its business, financial position, results of operations and prospects.
Climate change regulation at the federal, state or regional levels could result in increased operating and capital costs for TEP.
Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas and products produced from crude oil, are examples of GHGs. The United States Environmental Protection Agency (the “EPA”), has determined that the emission of GHGs present an endangerment to public health and the environment because emissions of such gases contribute to the warming of the Earth’s atmosphere and other climatic changes. Various laws and regulations exist, or are under development that seek to regulate the emission of such GHGs, including the EPA programs to control GHG emissions and state actions to develop statewide or regional programs. In recent years, the U.S. Congress has considered, but not adopted, legislation to reduce emissions of GHGs.
Based on these findings, the EPA began adopting and implementing regulations to restrict the emission of GHGs under existing provisions of the federal Clean Air Act (the “CAA”), starting in 2011. The EPA has issued a final rule, known as the “Tailoring Rule,” that defines regulatory emission thresholds at which certain new and modified stationary sources are subject to permitting and other requirements for GHG emissions under the CAA’s Prevention of Significant Deterioration (“PSD”) and Title V programs. The EPA has indicated in rule makings that it may reduce the current regulatory thresholds for GHGs, making additional sources subject to PSD permitting requirements. On June 23, 2014, the United States Supreme Court ruled that portions of EPA’s GHG regulatory program violated the CAA. Specifically, the Supreme Court determined that GHGs cannot independently trigger PSD permitting requirements. However, the Court held that certain PSD permitting requirements may apply to GHG emissions if emissions of another regulated pollutant, like sulfur dioxide or particulate matter, trigger PSD permitting. Additionally, the Supreme Court ruled that the Tailoring Rule thresholds violated the CAA, while suggesting that EPA could promulgate “de minimis” thresholds for GHGs. On April 10, 2015, the United States Court of Appeals for the District of Columbia Circuit issued an order that vacates EPA’s regulations to the extent that they allow GHGs to independently trigger PSD permitting requirements and that requires EPA to revise its regulations accordingly and to assess the need for other regulatory changes to implement the Supreme Court’s decision.
Some of TEP’s facilities emit GHGs in excess of the Tailoring Rule thresholds and have been required to obtain a Title V Permit that reflects this potential to emit GHGs. Although these existing facilities are not currently required to obtain a PSD permit containing enforceable limits on GHG emissions, any future modifications with a potential to emit GHGs above the applicable regulatory thresholds at the time of the application, and to emit a regulated non-GHG pollutant in excess of statutory thresholds as well, would require TEP to obtain a PSD permit containing enforceable limits on GHG emissions. TEP notes that, as described above, the Supreme Court’s recent decision on EPA’s GHG rules creates some uncertainty regarding applicable regulatory thresholds for GHG emissions for facilities that trigger permitting requirements based on emissions of non-GHG pollutants.
Additional direct regulation of GHG emissions in TEP’s industry may be implemented under other CAA programs, including the New Source Performance Standards (“ NSPS”) program. The EPA has already proposed to regulate GHG emissions from certain electric generating units under the NSPS program. While these proposed regulations for electric generating units would not apply to TEP’s operations, the EPA may propose to regulate additional sources under the NSPS program. For example, the EPA has proposed a rule that it calls the “Clean Power Plan” to compel state governments to reduce GHG emissions from sources within their jurisdictions. In addition, in 2009, the EPA published a final rule requiring that specified large GHG emissions sources annually report the GHG emissions for the preceding year in the United States. In 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transportation compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule requires reporting of GHG emissions by regulated facilities to the EPA on an annual basis. Some of TEP’s facilities are required to report under this rule, and operational and/or regulatory changes could require additional facilities to comply with GHG emissions reporting requirements.
At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs, primarily through the planned development of emission inventories or regional greenhouse gas “cap and trade” programs. Many of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. Depending on the particular program, TEP could be required to purchase and surrender emission allowances and its customers may find it less attractive to produce, own, ship or have natural gas or crude oil processed or refined.
Because TEP’s operations, including its compressor stations and processing facilities, emit various types of GHGs, primarily methane and carbon dioxide, new legislation or regulation could increase its costs related to operating and maintaining its facilities, and could delay future permitting. Depending on the particular new law, regulation or program adopted, TEP could be required to incur capital expenditures for installation of new emission controls on its compressor stations and processing facilities, acquire and surrender allowances for its GHG emissions, pay taxes related to its GHG emissions and administer and manage a GHG emissions program. TEP is not able at this time to estimate such increased costs; however, they could be significant. While TEP may be able to include some or all of such increased costs in the rates charged by its pipelines, such recovery of costs is uncertain in all cases and may depend on events beyond its control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or other regulations.
Similarly, while TEP may be able to recover some or all of such increased costs in the rates charged by its processing facilities, such recovery of costs is uncertain and may depend on the terms of its contracts with its customers. Any of the foregoing could have a material adverse effect on its business, financial position, results of operations and prospects. To the extent financial markets view climate change and greenhouse gas emissions as a financial risk, this could materially and adversely impact its cost of and access to capital. Legislation or regulations that may be adopted to address climate change, or incentives to conserve energy or use alternative energy sources, could also affect the markets for its services by making natural gas and crude oil products less desirable than competing sources of energy.
TEP’s operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose it to significant costs, liabilities and expenditures that could exceed its current expectations.
Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in natural gas transportation, storage and processing and crude oil transportation operations, and as a result, TEP may be required to make substantial expenditures that could exceed current expectations. TEP’s operations are subject to extensive federal, state, and local laws and regulations governing health and safety aspects of its operations, environmental protection, including the discharge of materials into the environment, and the security of chemical and industrial facilities. These laws include, but are not limited to, the following:
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CAA and analogous state laws, which impose obligations related to air emissions;
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Clean Water Act (“CWA”) and analogous state laws, which regulate discharge of pollutants (Section 402) or fill material (Section 404) from TEP’s facilities to state and federal waters, including wetlands;
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Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by TEP or locations to which TEP has sent wastes for disposal;
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Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, which impose requirements for the handling and discharge of hazardous and nonhazardous solid waste from TEP’s facilities;
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Occupational Safety and Health Act (“OSHA”) which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;
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The National Environmental Policy Act (“NEPA”) which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment;
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The Migratory Bird Treaty Act (“MBTA”) which implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;
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Endangered Species Act (“ESA”) and analogous state laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species;
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Bald and Golden Eagle Protection Act (“BGEPA”) prohibits anyone, without a permit issued by the Secretary of the Interior, from “taking” bald or golden eagles, including their parts, nests, or eggs. The Act defines “take” as “pursue, shoot, shoot at, poison, wound, kill, capture, trap, collect, molest or disturb;”
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The Oil Pollution Act (“OPA”) and analogous laws, which imposes liability for discharges of oil into waters of the United States and requires facilities which could be reasonably expected to discharge oil into waters of the United States to maintain and implement appropriate spill contingency plans; and
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National Historic Preservation Act (“NHPA”) and analogous state laws, which is intended to preserve and protect historical and archeological sites.
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Various governmental authorities, including but not limited to the EPA, the U.S. Department of the Interior, the U.S. Department of Homeland Security, and analogous Federal, State and local agencies have the power to enforce compliance with these laws and regulations and the permits and related plans issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, permits, plans and agreements may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of TEP’s operations, and delays in granting permits.
There is inherent risk of the incurrence of environmental costs and liabilities in TEP’s business, some of which may be material, due to its handling of the products it transports, processes and stores, air emissions related to its operations, historical industry operations, and waste disposal practices, and the prior use of flow meters and manometers containing mercury. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including but not limited to CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of materials associated with oil, natural gas and wastes on, under, or from TEP’s properties and facilities. TEP is currently conducting remediation at several sites to address contamination. For 2014, TEP spent approximately $270,000 and for 2015 has budgeted approximately $691,000 for these ongoing environmental remediation projects. Private parties, including but not limited to the owners of properties through which TEP’s pipelines pass and facilities where its wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws, regulations and permits issued thereunder, or for personal injury or property damage arising from its operations. Some sites at which TEP operates are located near current or former third-party hydrocarbon storage and processing or natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours that could result in remedial action. In addition, increasingly strict laws, regulations and enforcement policies could materially increase its compliance costs and the cost of any remediation that may become necessary. TEP’s insurance does not cover all environmental risks and costs and may not provide sufficient coverage if an environmental claim is made against TEP.
In June 2013, the EPA extended its National Enforcement Initiatives, enforcement priorities list, including an initiative related to Energy Extraction Activities, for 2014 through 2016. TEP cannot predict what the results of the current initiative or any future initiative will be, or whether federal, state or local laws or regulations will be enacted in this area. If new regulations are imposed related to oil and gas extraction, the volumes of natural gas and crude oil that TEP transports and/or processes could decline and its results of operations could be materially adversely affected.
TEP’s business may be materially and adversely affected by changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits or plans developed thereunder. Also, TEP might not be able to obtain or maintain from time to time all required environmental regulatory approvals for its operations, or may have to implement contingencies or conditions in order to obtain such approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if TEP fails to obtain and comply with them, the operation or construction of its facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to its business, financial condition, results of operations and cash flows.
TEP is also generally responsible for all liabilities associated with the environmental condition of its facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, TEP could acquire, or be required to provide indemnification against, environmental liabilities that could expose TEP to material losses, which may not be covered by insurance. In addition, the steps TEP could be required to take to bring certain facilities into compliance could be prohibitively expensive, and TEP might be required to shut down, divest or alter the operation of those facilities, which might cause TEP to incur losses. For example, in August 2011, the EPA and the Wyoming Department of Environmental Quality conducted an inspection of the Leak Detection and Repair Program (“LDAR”) at the Casper Plant in Wyoming. In September 2011, Tallgrass Midstream received a letter from the U.S. EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the CAA. Tallgrass Midstream received a letter from the U.S. EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the U.S. EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including attempted resolution of more recently identified LDAR issues. TEP is not currently able to estimate the costs that may be associated with a settlement or other resolution of this matter, which could be substantial.
TEP has agreed to a number of conditions in its environmental permits and associated plans, approvals and authorizations that require the implementation of environmental habitat restoration, enhancement and other mitigation measures that involve, among other things, ongoing maintenance and monitoring. Governmental authorities may require, and community groups and private persons may seek to require, additional mitigation measures in the future to further protect ecologically sensitive areas where TEP currently operates, and would operate if its facilities are extended or expanded, or if TEP constructs new facilities, and TEP is unable to predict the effect that any such measures would have on its business, financial position, results of operations or prospects.
Further, such existing laws and regulations may be revised or new laws or regulations may be adopted or become applicable to TEP. In addition to potential GHG regulations, there may also be potential regulations under the NSPS and/or the maximum available control technology standard that may affect TEP. Also, EPA and the U.S. Army Corps of Engineers recently issued a final rule to clarify the term “waters of the United States” as regards federal jurisdiction under the CWA. Many interested parties believe that the rule will expand federal jurisdiction under the CWA. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. 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 materially different from the amounts TEP currently anticipates. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from its customers, could have a material adverse effect on its business, financial position, results of operations and prospects.
Increased regulation of hydraulic fracturing and other oil and natural gas processing operations could affect TEP’s operations and result in reductions or delays in production by its customers, which could have a material adverse impact on its revenues.
A portion of TEP’s customers’ oil and natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into shale formations to stimulate production. Hydraulic fracturing is currently exempt from federal regulation pursuant to the federal Safe Drinking Water Act (“SDWA”) (except when the fracturing fluids or propping agents contain diesel fuels, and EPA released guidance on the permitting of wells that use diesel fuels during hydraulic fracturing activities in February 2014), because hydraulic fracturing is excluded from the SDWA definition of “underground injection” and therefore is not subject to permitting and federal regulatory control pursuant to SDWA. However, public concerns have been raised related to its potential environmental impact. Additional federal, state and local laws and regulations to more closely regulate hydraulic fracturing have been considered and, in some cases, adopted and implemented. For example, from time to time, legislation to further regulate hydraulic fracturing has been proposed in Congress, including repeal of the
SDWA exemption for hydraulic fracturing, as well as to require disclosure for chemicals used in hydraulic fracturing. An EPA investigation requested by a committee of the House of Representatives to assess the potential environmental effects of hydraulic fracturing on drinking water and groundwater is underway, with a first progress report outlining work currently underway by the agency released on December 21, 2012, and a final draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources was expected to be available for public comment and peer review in 2014, although it has not yet been released. Reports prepared by the U.S. Department of Energy’s Shale Gas Subcommittee could also lead to further restrictions on hydraulic fracturing. In addition, EPA has announced its intention to propose regulations under the CWA regarding wastewater discharges from hydraulic fracturing and other gas production and, on May 9, 2014, EPA issued an Advance Notice of Proposed Rulemaking under Section 8 of the Toxic Substances Control Act (the “TSCA”) to seek public comment on hydraulic fracturing chemical information that could be reported and disclosed under TSCA. Most recently, the federal Bureau of Land Management (the “BLM”) issued a final rule on March 20, 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands including, among other things, submission of various detailed notices, plans and other information relating to the fracturing activities that are subject to BLM pre-approval, implementation of measures designed to protect usable water from fracturing activities; and public disclosure of chemicals used in hydraulic fracturing fluids through the FracFocus website. The BLM rule has an expected effective date of June 2015 but is currently subject to one or more legal challenges that seek to block implementation of the rule.
Apart from federal legislation and EPA regulations, other federal agencies and states have proposed or adopted legislation or regulations restricting hydraulic fracturing. On May 24, 2013, the U.S. Department of Interior published a proposed rule in the Federal Register that includes disclosure requirements and other mandates for hydraulic fracturing on federal lands. Some states have already imposed disclosure requirements associated with hydraulic fracturing, including states in which TEP operates.
Moreover, some state and local authorities have considered or imposed new laws and rules related to hydraulic fracturing, including additional permit requirements, operational restrictions, chemical disclosure obligations and temporary or permanent bans or, in municipal settings, time, place and manner restrictions, on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas. For example, Wyoming, Kansas, Colorado, North Dakota, Montana, and Oklahoma have imposed regulations regarding disclosure of information regarding chemicals in well stimulation operations. The Governor of Colorado recently announced that he would form a task force to consider additional regulation of oil and gas activities, including hydraulic fracturing. Although TEP does not have operations in the State of New York, the Governor of New York announced in December 2014 that hydraulic fracturing would be banned in that state. Many local governments have restricted or banned hydraulic fracturing within their jurisdictions, including some in states in which TEP operates.
State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in minor seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of minor seismic events have reduced injection volumes or suspended operations, often voluntarily. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. However, some state regulatory agencies have modified their regulations to account for induced seismicity. For example, the Texas Railroad Commission (the “TRC”) rules allow the TRC to modify, suspend, or terminate a permit based on a determination that the permitted activity is likely to be contributing to seismic activity. Regulatory agencies are continuing to study possible linkage between injection activity and induced seismicity.
TEP cannot predict whether any additional federal, state or local laws or regulations will be enacted in this area and if so, what their provisions would be. If additional levels of reporting, regulation or permitting moratoria were required or imposed related to hydraulic fracturing, the volumes of crude oil and natural gas that TEP transports may decline and its results of operations could be materially and adversely affected. Further, additional state legislation or regulation may impact any potential expansion plans by delaying implementation or requiring additional approvals or modifications to expansion plans.
In addition, the EPA approved final rules that establish new air emission controls for oil and natural gas production, pipelines and processing operations that became effective on October 15, 2012. For new or reworked hydraulically fractured gas wells, the rules require the control of emissions through flaring or reduced emission, or green, completions until January 1, 2015. As of 2015, the rule requires the use of green completions by all such wells except wildcat (exploratory) and delineation gas wells and low reservoir pressure non-wildcat and non-delineation gas wells. The rules also establish specific new requirements regarding emissions from wet seal and reciprocating compressors at production facilities, gathering systems, boosting facilities and onshore natural gas processing plants, effective October 15, 2012, and from pneumatic controllers and storage vessels at production facilities, gathering systems, boosting facilities and onshore natural gas processing plants, effective October 15, 2013. In addition, the rules revise existing requirements for volatile organic compound emissions (“VOCs”) from equipment leaks at onshore natural gas processing plants by lowering the leak definition for valves from 10,000
parts per million to 500 parts per million and requiring the monitoring of connectors, pumps, pressure relief devices and open-ended lines, effective October 15, 2012. These rules may therefore require a number of modifications to TEP’s and TEP’s customers’ operations, including the installation of new equipment to control emissions. In October 2012 several challenges to EPA’s rules were filed by various parties, including environmental groups and industry associations. In a January 1, 2013 unopposed motion to hold this litigation in abeyance, EPA indicated that it may reconsider some aspects of the rule and has since reconsidered certain aspects of the rule. The case is currently in abeyance and EPA may reconsider other aspects of the rule. Depending on the outcome of such proceedings, the rules may be modified or rescinded or EPA may issue new rules, the costs of compliance with any modified or newly issued rules cannot be predicted. Additionally, EPA has signaled its intent to regulate emissions of methane and volatile organic compounds from the oil and gas sector as a measure to implement President Obama’s Climate Action Plan. EPA has released a series of white papers addressing methane reductions from the oil and gas sector. On January 14, 2015, the Obama Administration announced that EPA will propose a rule in the summer of 2015 to set standards for methane and VOC emissions from new and modified sources in the oil and gas sector, including transmission. A final rule is expected in 2016. The Obama Administration’s announcement also stated that other federal agencies, including PHMSA and the Department of Energy, will impose new or more stringent regulations on the oil and gas sector that will have the effect of reducing methane emissions. Depending on whether rules are promulgated and the applicability and restrictions in any promulgated rule, compliance with such rules could result in additional costs, including increased capital expenditures and operating costs. While TEP is not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, they could be significant for TEP. Compliance with such rules may also make it more difficult for TEP’s customers to operate, thereby reducing the volume of natural gas or crude oil transported through its pipelines or the volumes of natural gas it processes, which may adversely affect its business. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for TEP and its customers, which could have a material adverse effect on its business.
Potential increased costs as a result of EPA regulation of internal combustion engines could be significant.
Internal combustion engines used in TEP’s operations are also subject to EPA regulation under the CAA. The EPA published new regulations on emissions of hazardous air pollutants from reciprocating internal combustion engines on August 20, 2010. On January 14, 2013, the EPA signed a final rule amending these regulations and it was published in the Federal Register on January 30, 2013. The EPA also revised the NSPS for stationary compression ignition and spark ignition internal combustion engines on June 28, 2011 and made minor amendments, included in the January 14, 2013 final rule. Compliance with these new regulations may require significant capital expenditures for physical modifications and may require operational changes as well. TEP anticipates modest future cost increases for compliance with these rules, as activities such as routine major engine overhauls or facility permitting changes could subject existing engines to rule requirements which were not previously applicable.
TEP is exposed to costs associated with lost and unaccounted for volumes.
A certain amount of natural gas and crude oil may be lost or unaccounted for in normal operations in connection with their transportation across a pipeline system. Under its tariffs and contractual arrangements with its customers TEP is entitled to retain a specified volume of natural gas and crude oil in order to compensate TEP for such lost and unaccounted for volumes, as well as the natural gas used to run its natural gas compressor stations, which TEP refers to collectively as fuel usage. TEP’s pipeline tariffs, other than the Trailblazer Pipeline’s, do not contain fuel usage true-up mechanisms. The use of fuel (natural gas, electric and lost and unaccounted for gas) trackers on the Trailblazer Pipeline, while minimizing risk over time, nevertheless leaves the Trailblazer Pipeline exposed to the possibility of under- or over-collections on an annual basis. The level of lost and unaccounted for volumes, and natural gas fuel usage, on TEP’s pipeline systems may exceed the natural gas and crude oil volumes retained from its customers as compensation for its lost and unaccounted for volumes, and fuel usage, pursuant to its tariffs and contractual agreements, and it may be necessary to purchase natural gas or crude oil in the market to make up for the difference, which exposes TEP to commodity price risk. Future exposure to the volatility of natural gas and crude oil prices as a result of lost and unaccounted for volume imbalances could have a material adverse effect on its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.
TEP has certain long term fixed priced natural gas and crude oil transportation contracts that cannot be adjusted even if its costs increase, and TEP has certain crude oil transportation contracts that contain favored nation provisions that could require rate decreases if other similarly situated shippers are paying lower rates. As a result, its costs could exceed its revenues.
Approximately one-third of TEP’s contracted natural gas transportation firm capacity is provided under long-term, fixed price “negotiated rate” contracts that are not subject to adjustment, even if its cost to perform such services exceeds the revenues received from such contracts, and, as a result, its costs could exceed its revenues received under such contracts. It is possible that costs to perform services under TEP’s “negotiated rate” contracts will exceed the negotiated rates. If this occurs, it could decrease the cash flow realized by TEP’s assets and, therefore, the cash it has available for distributions to its 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 fixed between the natural gas pipeline and the shipper for the contract term and does not necessarily vary with changes in the level of cost-based “recourse rates,” provided that the affected customer is willing to agree to such rates and that the FERC has approved the negotiated rate agreement. 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. Any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, under current FERC policy, may be recoverable from other shippers in certain limited circumstances. For example, the FERC may recognize this shortfall in the determination of prospective rates in a future rate case.
Approximately 90% of TEP’s crude oil pipeline capacity is provided to committed shippers under long-term “Throughput and Deficiency Agreements” (“TDAs”). Rates under the TDAs are typically subject to increase only through the FERC annual index process. TEP generally cannot file for rate increases outside of the annual FERC adjustment process with respect to committed shippers who have signed TDAs. Some of the TDAs also contain favored nations provisions which could result in lower rates being charged to certain committed shippers to ensure that the rates such shippers are paying are no greater than ninety to one hundred percent of the rates being charged to other similarly situated shippers for similar service at similar volumes and terms.
Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on TEP’s natural gas storage business.
Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for TEP’s 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 its services and the rates it is 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, then demand for TEP’s storage services and the prices that it 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. Alternatively, 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 its business, financial condition, results of operations and ability to make distributions.
Certain portions of TEP’s transportation, storage and processing facilities have been in service for several decades. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with its facilities that could have a material adverse effect on its business and results of operations.
Significant portions of TEP’s transportation, storage and processing systems have been in service for several decades. The age and condition of its facilities could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce its revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of its facilities could adversely affect its business and results of operations and its ability to make cash distributions to its unitholders.
Restrictions in TEP’s revolving credit facility could adversely affect its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.
TEP’s revolving credit facility limits its ability to, among other things:
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incur or guarantee additional debt;
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redeem or repurchase units or make distributions under certain circumstances;
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make certain investments and acquisitions;
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incur certain liens or permit them to exist;
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enter into certain types of transactions with affiliates;
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merge or consolidate with another company; and
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transfer, sell or otherwise dispose of assets.
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TEP’s revolving credit facility also contains covenants requiring it to maintain certain financial ratios. Its ability to meet those financial ratios and tests can be affected by events beyond its control, and TEP cannot assure us that it will meet those ratios and tests.
The provisions of TEP’s revolving credit facility may affect its ability to obtain future financing and pursue attractive business opportunities and its flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of its revolving credit facility, including a failure to meet the required financial ratios and tests, could result in a default or an event of default that could enable its lenders to restrict or prohibit its ability to make quarterly distributions and declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of its debt is accelerated, its assets may be insufficient to repay such debt in full, and its unitholders could experience a partial or total loss of their investment.
All of the membership interests in TEP GP that are owned by Tallgrass Equity are pledged as security under Tallgrass Equity’s credit facility. Upon an event of default under that credit facility, a change in control of TEP could result.
Tallgrass Equity pledged all of the equity interests it holds in TEP GP as collateral under its new revolving credit facility, which contains customary and other events of default. Upon an event of default, the lenders under Tallgrass Equity’s credit facility could foreclose on its collateral, which could result in a change in control of TEP GP and a change in indirect ownership of the general partner interests and incentive distribution rights in TEP held by TEP GP. Such change in control would constitute an immediate event of default under TEP’s credit facility, which would permit the lenders under TEP’s credit facility to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable.
TEP’s future debt levels may limit its flexibility to obtain financing and to pursue other business opportunities.
TEP’s level of debt could have important consequences to TEP, including the following:
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its 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;
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its funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of its cash flow required to make interest payments on its debt;
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it may be more vulnerable to competitive pressures or a downturn in its business or the economy generally; and
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its flexibility in responding to changing business and economic conditions may be limited.
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Its ability to service its debt depends upon, among other things, its future financial and operating performance, which is affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond its control. If its operating results are not sufficient to service its current or future indebtedness, TEP will be forced to take actions such as reducing distributions, reducing or delaying its business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. TEP may not be able to effect any of these actions on satisfactory terms or at all.
Increases in interest rates could adversely impact demand for TEP’s storage capacity, its unit price, its ability to issue equity or incur debt for acquisitions or other purposes and its ability to make cash distributions at its intended levels.
There is a financing cost for TEP’s customers to store natural gas in its storage facilities. That financing cost is impacted by the cost of capital or interest rate 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 its 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 its financing costs to increase accordingly. As with other yield-oriented securities, its unit price is impacted by the level of its 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 TEP’s units, and a rising interest rate environment could have an adverse impact on its unit price, its ability to issue equity or incur debt for acquisitions or other purposes and its ability to make cash distributions at its intended levels.
Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect its business and results of operations.
TEP’s business may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are reduced energy demand and lower prices for its services and increased difficulty in collecting amounts owed to TEP by its customers which could reduce its access to credit markets, raise the cost of such access or require TEP to provide additional collateral to its counterparties. TEP’s ability to access available capacity under its revolving credit facility could be impaired if one or more of its lenders fails to honor its contractual obligation to lend to TEP. If financing is not available when needed, or is available only on unfavorable terms, TEP may be unable to implement its business plans or otherwise take advantage of business opportunities or respond to competitive pressures.
The amount of cash TEP has available for distribution to unitholders depends primarily on its cash flow rather than on its profitability, which may prevent it from making distributions, even during periods in which TEP records net income.
The amount of cash TEP has available for distribution depends primarily upon its cash flow and not solely on profitability, which is affected by non-cash items. As a result, TEP may make cash distributions during periods when its records losses for financial accounting purposes and may not make cash distributions during periods when it records net earnings for financial accounting purposes.
The lack of diversification of TEP’s assets and geographic locations could adversely affect its ability to make distributions to its common unitholders.
TEP relies primarily on revenues generated from transportation, storage and processing systems that it owns, which are primarily located in the Rocky Mountain and Midwest regions of the United States. Due to its lack of diversification in assets and geographic location, an adverse development in these businesses or its areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in demand for crude oil or natural gas, could have a significantly greater impact on its results of operations and cash available for distribution to its common unitholders than if TEP maintained more diverse assets and locations.
TEP does not own most of the land on which its natural gas and crude oil pipeline systems and Midstream Facilities are located, which could disrupt its operations and subject it to increased costs.
TEP does not own most of the land on which its pipeline systems and Midstream Facilities have been constructed, and TEP is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if TEP does not have valid rights-of-way, if such rights-of-way lapse or terminate or if its facilities are not properly located within the boundaries of such rights-of-way. For example, the West Frenchie Draw treating facility is located on land leased from the Wyoming Board of Land Commissioners pursuant to a contract that can be terminated at any time. Although many of these rights are perpetual in nature, TEP occasionally obtains the right to construct and operate pipelines on other owners’ land for a specific period of time. If TEP was to be unsuccessful in renegotiating rights-of-way, it might incur increased costs to maintain its pipeline systems, which could have a material adverse effect on its business, results of operations, financial condition and ability to make distributions to its unitholders. In addition, TEP is subject to the possibility of increased costs under its rental agreements with landowners, primarily through rental increases and renewals of expired agreements.
Some rights-of-way for its pipeline systems and other real property assets are shared with other pipeline systems and other assets owned by third parties. TEP or owners of the other pipeline systems may not have commenced or concluded eminent domain proceedings for some rights-of-way. In some instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants.
TEP’s interstate natural gas pipeline systems have federal eminent domain authority. Whether TEP has the power of eminent domain for the Pony Express crude oil pipeline varies from state to state, depending upon the laws of the particular state. Regardless, TEP must compensate landowners for the use of their property, which may include any loss of value to the remainder of their property not being used by TEP, which are sometimes referred to as “severance damages.” Severance damages are often difficult to quantify and their amount can be significant. In eminent domain actions, such compensation may be determined by a court. TEP’s inability to exercise the power of eminent domain could negatively affect its business if TEP were to lose the right to use or occupy the property on which its crude oil or natural gas pipeline systems are located.
TEP’s operations are dependent on its rights and ability to receive or renew the required permits and other approvals from governmental authorities and other third parties.
Performance of its operations requires that TEP obtain and maintain numerous environmental and land use permits and other approvals authorizing its business activities. A decision by a governmental authority or other third party to deny, delay or restrictively condition the issuance of a new or renewed permit or other approval, or to revoke or substantially modify an existing permit or other approval, could have a material adverse effect on its ability to initiate or continue operations at the affected location or facility. Expansion of its existing operations is also predicated on securing the necessary environmental or land use permits and other approvals, which TEP may not receive in a timely manner or at all.
In order to obtain permits and renewals of permits and other approvals in the future, TEP may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time needed to develop a site or pipeline alignment. Also, obtaining or renewing required permits or other approvals is sometimes delayed or prevented due to community opposition and other factors beyond TEP’s control. The denial of a permit or other approval essential to its operations or the imposition of restrictive conditions with which it is not practicable or feasible to comply could impair or prevent its ability to develop or expand a property or right-of-way. Significant opposition to a permit or other approval by neighboring property owners, members of the public or non-governmental organizations, or other third parties or delay in the environmental review and permitting process also could impair or delay TEP’s ability to develop or expand a property or right-of-way. New legal requirements, including those related to the protection of the environment, could be adopted at the federal, state and local levels that could materially adversely affect TEP’s operations (including its ability to store, transport or process natural gas or crude oil or the pace of storing, transporting or processing natural gas or crude oil), its cost structure or its customers’ ability to use its services. Such current or future regulations could have a material adverse effect on its business and TEP may not be able to obtain or renew permits or other approvals in the future.
A shortage of skilled labor in the midstream industry could reduce labor productivity and increase costs, which could have a material adverse effect on TEP’s business and results of operations.
The transportation, storage and processing of natural gas, the transportation of crude oil and the fractionation of NGLs requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. If TEP experiences shortages of skilled labor in the future, its labor and overall productivity or costs could be materially and adversely affected. If TEP’s labor prices increase or if it experiences materially increased health and benefit costs for employees, its results of operations could be materially and adversely affected.
If TEP fails to develop or maintain an effective system of internal controls, it may not be able to report its financial results accurately or prevent fraud, which would likely have a negative impact on the market price of its common units.
Upon the completion of its initial public offering, TEP became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended. Effective internal controls are necessary for TEP to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. TEP’s efforts to develop and maintain its internal controls may not be successful, and TEP may be unable to maintain effective controls over its financial processes and reporting in the future or to comply with its obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which TEP refers to as Section 404. For example, Section 404 requires TEP, among other things, to annually review and report on, and its independent registered public accounting firm to attest to, the effectiveness of its internal controls over financial reporting (except for the requirement for an auditor’s attestation report, as described below). Any failure to develop, implement or maintain effective internal controls or to improve TEP’s internal controls could harm its operating results or cause it to fail to meet its reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, TEP can provide no assurance as to its, or its independent registered public accounting firm’s, conclusions about the effectiveness of its internal controls, and TEP may incur significant costs in its efforts to comply with Section 404. Ineffective internal controls will subject TEP to regulatory scrutiny and a loss of confidence in TEP’s reported financial information, which could have an adverse effect on its business and would likely have a negative effect on the trading price of its common units.
For as long as TEP is an emerging growth company, TEP 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 JOBS Act. For as long as TEP remains an “emerging growth company” as defined in the JOBS Act, TEP intends to continue taking 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 its system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations
regarding executive compensation in its periodic reports. TEP will remain an emerging growth company for up to five full fiscal years, although TEP will lose that status sooner if it has more than $1.0 billion of revenues in a fiscal year, has more than $700 million in market value of its limited partner interests held by non-affiliates on the last business day of the most recently completed second fiscal quarter, or issues more than $1.0 billion of non-convertible debt over a three-year period.
To the extent that TEP relies on any of the exemptions available to emerging growth companies, you will receive less information about its executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find TEP’s common units to be less attractive as a result, there may be a less active trading market for its common units and its trading price may be more volatile.
TEP’s election to take advantage of the JOBS Act extended accounting transition period may make its financial statements more difficult to compare to other public companies.
Pursuant to the JOBS Act, as an “emerging growth company,” TEP must make an election to opt in or opt out of the extended transition period for any new or revised accounting standards that may be issued by the PCAOB or the SEC. TEP has elected to take advantage of such extended transition period which means that when a standard is issued or revised and it has different application dates for public or private companies, TEP can, for so long as TEP is an “emerging growth company,” adopt the standard for private companies. This may make comparison of its financial statements with any other public company that either is not an “emerging growth company” or has opted out of using the extended transition period difficult or impossible as a result of TEP’s use of different accounting standards.
The outcome of future rate cases will determine the amount of income taxes that TEP will be allowed to recover.
In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in its cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. The extent to which owners of pipelines have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established. An adverse determination by the FERC with respect to this issue could have a material adverse effect on TEP’s revenues, earnings and cash flows.
TEP’s business could be negatively impacted by security threats, including cyber security threats, and related disruptions.
TEP relies on its information technology infrastructure to process, transmit and store electronic information, including information it uses to safely operate its assets. TEP may face cyber security and other security threats to its information technology infrastructure, which could include threats to its operational and safety systems that operate its pipelines, plants and assets. TEP could face unlawful attempts to gain access to its information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of its current information technology infrastructure and software assets and its ability to maintain and upgrade such assets could affect its ability to resist cyber security threats. TEP could also face attempts to gain access to information related to its assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information, otherwise known as “social engineering.”
TEP’s information technology infrastructure is critical to the efficient operation of its business and essential to its ability to perform day-to-day operations. Breaches in its information technology infrastructure or physical facilities, or other disruptions, could result in damage to its assets, service interruptions, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on its operations, financial position, results of operations and prospects.
If TEP is unable to protect its information and telecommunication systems against disruptions or failures, its operations could be disrupted.
TEP relies extensively on computer systems to process transactions, maintain information and manage its business. Disruptions in the availability of its computer systems could impact its ability to service its customers and adversely affect its sales and results of operations. TEP is dependent on internal and third party information technology networks and systems, including the Internet and wireless communications, to process, transmit and store electronic information. Its computer systems are subject to damage or interruption due to system replacements, implementations and conversions, power outages, computer or telecommunication failures, computer viruses, security breaches, catastrophic events such as fires, tornadoes, snowstorms and floods and usage errors by its employees. If TEP’s computer systems are damaged or cease to function properly, it may have to make a significant investment to fix or replace them, and TEP may have interruptions in its ability to service its customers. Although TEP attempts to eliminate or reduce these risks by using redundant systems, this disruption caused by the unavailability of its computer systems could nevertheless significantly disrupt its operations or may result in financial damage or loss due to, among other things, lost or misappropriated information.
Tax Risks
As our only cash-generating assets consist of our partnership interest in Tallgrass Equity and its related direct and indirect interests in TEP, our tax risks are primarily derivative of the tax risks associated with an investment in TEP.
The tax treatment of TEP depends on its status as a partnership for U.S. federal income tax purposes, as well as it not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat TEP as a corporation or TEP becomes subject to additional amounts of entity-level taxation for state or foreign tax purposes, it would reduce the amount of cash available for distribution to us and increase the portion of our distributions treated as taxable dividends.
We own a 30.35% membership interest in Tallgrass Equity, which directly owns the Acquired TEP Units and indirectly owns all of TEP’s IDRs and TEP’s general partner interest (which was approximately 1.37% as of March 31, 2015). Accordingly, the value of our indirect investment in TEP, as well as the anticipated after-tax economic benefit of an investment in our Class A shares, depends largely on TEP being treated as a partnership for federal income tax purposes, which requires that 90% or more of TEP’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”).
Despite the fact that TEP is a limited partnership under Delaware law and, unlike us, has not elected to be treated as a corporation for federal income tax purposes, it is possible, under certain circumstances, for TEP to be treated as a corporation for federal income tax purposes. A change in TEP’s business could cause it to be treated as a corporation for federal income tax purposes or otherwise subject it to federal income taxation as an entity. For example, TEP would be treated as a corporation if less than 90% of its gross income for any taxable year consists of “qualifying income” within the meaning of Section 7704 of the Code.
If TEP were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income taxes at varying rates. Distributions to TEP’s partners, including Tallgrass Equity, would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to TEP’s partners. Because a tax would be imposed upon TEP as a corporation, its cash available for distribution would be substantially reduced. Therefore, treatment of TEP as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to us, likely causing a substantial reduction in the value of our Class A shares.
Current law may change, causing TEP to be treated as a corporation for federal income tax purposes or otherwise subjecting TEP to entity-level taxation. In addition, 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 any entity-level taxes on TEP will reduce its cash available for distribution to its partners.
TEP’s partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects TEP to taxation as a corporation or otherwise subjects TEP to entity-level taxation for federal income tax purposes, TEP’s minimum quarterly distribution and target distribution amounts will be adjusted to reflect the impact of that law on TEP. If this were to happen, the amount of distributions Tallgrass Equity receives from TEP and our resulting cash flows could be reduced substantially, which would adversely affect our ability to pay distributions.
Moreover, if TEP were treated as a corporation we would not be entitled to the deductions associated with our initial acquisition of interests in Tallgrass Equity or subsequent exchanges of retained Tallgrass Equity interests and Class B shares for our Class A shares. As a result, if TEP were treated as a corporation, (i) our liability for taxes would likely be higher, further reducing our cash available for distribution and (ii) a greater portion of the cash we are able to distribute would be treated as a taxable dividend.
We may incur substantial corporate income tax liabilities on our allocable share of TEP income.
We anticipate that available deductions will offset our taxable income for, at a minimum, each of the periods ending December 31, 2015, 2016 and 2017. This expectation is subject to numerous assumptions, including TEP’s earnings from its operations, the amount of those earnings allocated to us, the amount of distributions paid to us by TEP, and that there will not be an issuance of significant additional units by TEP without a corresponding increase in the aggregate tax deductions generated by TEP. These assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, our expectation is based on current tax law and tax reporting positions that we and TEP will adopt and with which the IRS could disagree. We are classified as a corporation for U.S. federal income tax purposes and, in most states in which TEP does business, for state income tax purposes. To the extent that TEP allocates to us net taxable income in any year, current law provides that we will be subject to U.S. federal income tax at rates of up to 35% (and a 20% alternative minimum tax in certain cases), and to state income tax at rates that vary from state to state. The amount of cash available for distribution to you will be reduced by the amount of any such income taxes payable by us for which we establish reserves.
The tax treatment of publicly traded partnerships such as TEP could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including TEP, may be modified by legislative, judicial, or administrative changes, or interpretations of applicable law at any time. Any modifications to the U.S. federal income tax laws that may be applied retroactively or prospectively could make it more difficult or impossible to meet the expectation of future cash distributions or reduce the cash available for distributions to our shareholders. For example, from time to time, the President or members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such recent legislative proposal would have eliminated, and the President proposed in his recently issued budget proposal to eliminate, the qualifying income exception upon which TEP relies for its treatment as a partnership for U.S. federal income tax purposes. TEP is unable to predict whether any of these changes or any other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of our indirect investment in TEP. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.
The sale or exchange of 50% or more of TEP’s capital and profits interests during any twelve-month period will result in its termination as a partnership for federal income tax purposes.
TEP will be considered to have technically terminated as a partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a twelve-month period. Tallgrass Development and its direct and indirect owners own a substantial interest in the capital and profits of TEP. Therefore, a transfer by them of all or a portion of their interests in TEP could result in a termination of TEP for U.S. federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. TEP’s termination would, among other things, result in a deferral of depreciation deductions allowable in computing TEP’s taxable income. A deferral of depreciation deductions could increase the amount of taxable income allocated to us from TEP which could increase our tax liabilities and thereby reduce the amount of cash available for distribution. TEP’s termination currently would not affect its classification as a partnership for federal income tax purposes, but could cause it to be subject to penalties if it were unable to determine that a termination occurred.
Taxable gain or loss on the sale of our Class A shares could be more or less than expected.
If a holder sells our Class A shares, the holder will recognize a gain or loss equal to the difference between the amount realized and the holder’s tax basis in those Class A shares. To the extent that the amount of our distributions exceeds our current and accumulated earnings and profits, the distributions will be treated as a tax free return of capital and will reduce a holder’s tax basis in the Class A shares. We do not expect to have any earnings and profits for, at a minimum, each of the periods ending December 31, 2015, 2016 and 2017. Because our distributions in excess of our earnings and profits decrease a holder’s tax basis in Class A shares, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the Class A shares.
Our current tax treatment may change, which could affect the value of our Class A shares or reduce our cash available for distribution.
Our expectation that we will have available deductions that will offset a substantial portion of our taxable income and that our distributions will not constitute taxable dividends for, at a minimum, each of the periods ending December 31, 2015, 2016, and 2017, is based on current law, including with respect to the amortization of basis adjustments associated with our acquisition of interests in Tallgrass Equity. Similarly, our expectation that exchanges by the Exchange Right Holders of their retained interests in Tallgrass Equity and Class B shares in us for our Class A shares in the future will result in additional tax deductions is based on current law with respect to such exchanges. Changes in federal income tax law relating to such tax treatment could result in (i) our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution and (ii) a greater portion of our distributions being treated as taxable dividends. Moreover, we are subject to tax in numerous jurisdictions. Changes in current law in these jurisdictions, particularly relating to the treatment of deductions attributable to acquisitions of interests in Tallgrass Equity, could result in our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution.
Any decrease in our Class A share price could adversely affect our amount of cash available for distribution.
Changes in certain market conditions may cause our Class A share price to decrease. If the Exchange Right Holders exchange their retained interests in Tallgrass Equity and Class B shares in us for our Class A shares at a point in time when our Class A share price is below the price at which Class A shares are being sold in this offering, the ratio of our income tax deductions to gross income would decline. This decline could result in our being subject to tax sooner than expected, our tax liability being greater than expected, or a greater portion of our distributions being treated as taxable dividends.
The IRS Form 1099-DIV that you receive from your broker may over-report your dividend income with respect to our shares for U.S. federal income tax purposes, and failure to report your dividend income in a manner consistent with the IRS Form 1099-DIV that you receive from your broker may cause the IRS to assert audit adjustments to your U.S. federal income tax return. If you are a non-U.S. holder of our shares, your broker or other withholding agent may overwithhold taxes from dividends paid to you, in which case you generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to claim a refund of the overwithheld taxes.
Distributions we pay with respect to our shares will constitute “dividends” for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. Distributions we pay in excess of our earnings and profits will not be treated as “dividends” for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of your tax basis in your shares and then as capital gain realized on the sale or exchange of such shares. We may be unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes.
If you are a U.S. holder of our Class A shares, the IRS Form 1099-DIV may not be consistent with our determination of the amount that constitutes a “dividend” to you for U.S. federal income tax purposes or you may receive a corrected IRS Form 1099-DIV (and you may therefore need to file an amended federal, state or local income tax return). We will attempt to timely notify you of available information to assist you with your income tax reporting (such as posting the correct information on our website). However, the information that we provide to you may be inconsistent with the amounts reported to you by your broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to your tax return.
If you are a non-U.S. holder of our Class A shares, “dividends” for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate (or such lower rate as may be specified by an applicable income tax treaty) unless the dividends are effectively connected with your conduct of a U.S. trade or business. In the event that we are unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes, or your broker or withholding agent chooses to withhold taxes from distributions in a manner inconsistent with our determination of the amount that constitutes a “dividend” for such purposes, your broker or other withholding agent may overwithhold taxes from distributions paid to you. In such a case, you generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Unregistered Sales of Equity Securities
On February 19, 2015, in connection with our formation, we issued 100% of the limited partner interests in TEGP to Tallgrass Energy Holdings, LLC (formerly known as Tallgrass Development GP, LLC) in exchange for $1,000. This transaction was exempt from registration under Section 4(2) of the Securities Act. There were no other unregistered sales of securities during the three months ended March 31, 2015.
Use of Proceeds
On May 6, 2015, our Registration Statement on Form S-1 (File No. 333-202258), as amended, filed with the SEC in connection with the Offering was declared effective. The Offering closed on May 12, 2015, and we sold 47,725,000 Class A shares to the public, including a 6,225,000 Class A share overallotment exercised by the underwriters. The price to the public was $29.00 per Class A share and the proceeds (net of underwriting discounts and commissions) totaled approximately $1.3 billion. Expenses related to the Offering included approximately $65.7 million for the underwriters’ discount. Citigroup Global Markets Inc., Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Morgan Stanley & Co. LLC, RBC Capital Markets, LLC and Wells Fargo Securities, LLC acted as joint book-running managers of the Offering.
We contributed the net proceeds of the Offering (excluding proceeds from the underwriters exercise of their option to purchase additional Class A shares) to Tallgrass Equity in exchange for Tallgrass Equity’s issuance to us of 41,500,000 Tallgrass Equity units.
At the closing of the Offering, Tallgrass Equity entered into a new $150 million revolving credit facility and borrowed $150 million, the proceeds of which were used, together with the net proceeds from the Offering that Tallgrass Equity received from us, to purchase 20 million TEP common units from TD at $47.68 per TEP common unit. Tallgrass Equity distributed the remaining proceeds to the Exchange Right Holders.
We used the proceeds from the sale of the underwriters’ purchase the additional 6,225,000 Class A shares to purchase 6,225,000 Tallgrass Equity units from the Exchange Right Holders. 6,225,000 Class B shares were cancelled as a result of the exercise of the underwriter’s option to purchase the additional 6,225,000 Class A shares. After the application of the net proceeds from the Offering, we own a 30.35% membership interest in Tallgrass Equity.