MIDCOAST ENERGY PARTNERS, L.P.
1100 Louisiana Street, Suite 3300
Houston, Texas 77002
August 7, 2013
Via EDGAR and Fedex
Securities and Exchange Commission
Division of Corporation Finance
100 F. Street, N.E. Washington, D.C. 20549-4628
| Attn: | Mara L. Ransom, Assistant Director |
| Division of Corporation Finance |
| Re: | Midcoast Energy Partners, L.P. |
| Registration Statement on Form S-1 |
| Filed June 14, 2013 |
| File No. 333-189341 |
Ladies and Gentlemen:
Set forth below are the responses of Midcoast Energy Partners, L.P., a Delaware limited partnership (“we” or the “Partnership”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated July 12, 2013 with respect to the Partnership’s Registration Statement on Form S-1 initially filed with the Commission on June 14, 2013, File No. 333-189341 (the “Registration Statement”).
Concurrently with the submission of this letter, the Partnership has filed through EDGAR Amendment No. 1 to the Registration Statement (“Amendment No. 1”). For your convenience, we have hand delivered five copies of this letter, as well as five copies of Amendment No. 1 marked to show all changes made since the initial filing of the Registration Statement.
For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold text.
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Registration Statement on Form S-1 Filed June 14, 2013
General
| 1. | We note a number of blank spaces throughout your registration statement for information that you are not entitled to omit under Rule 430A of Regulation C. Please allow us sufficient time to review your complete disclosure prior to any distribution of preliminary prospectuses. In addition, please be advised that you may not circulate copies of your prospectus until you have included an estimated price range and related information based on a bona fide estimate of the public offering within that range, as well as all other information required by the federal securities laws, except information you may exclude in reliance upon Rule 430A of Regulation C. When you complete the filing by filling in the blanks, please note that we may have additional comments. |
Response: We acknowledge the Staff’s comment and we undertake to provide in future amendments all information in the Registration Statement that we are not entitled to omit under Rule 430A of Regulation C. We will allow sufficient time for the Staff to review our complete disclosure and for us to respond to any comments that may result from the Staff’s review prior to the distribution of our prospectus.
| 2. | Prior to the effectiveness of the registration statement, please arrange to have FINRA call us or provide us with a letter indicating that FINRA has cleared your filing. |
Response: We acknowledge the Staff’s comment and undertake to have FINRA call, or provide a copy of the FINRA no-objections letter to, the Staff as soon as such information becomes available.
| 3. | All exhibits are subject to our review. Accordingly, please file or submit all of your exhibits with your next amendment, or as soon as possible. Please note that we may have comments on the legal and tax opinions, underwriting agreement and amended and restated agreement of limited partnership, as well as other exhibits once they are filed. Please understand that we will need adequate time to review these materials before accelerating effectiveness. |
Response: We acknowledge the Staff’s comment and undertake to provide in future amendments all omitted exhibits and opinions as soon as possible to allow adequate time for the Staff to review prior to our request to accelerate the effectiveness of the Registration Statement.
| 4. | We note references throughout your prospectus to third-party sources for statistical, qualitative and comparative statements contained in your prospectus. For example, you refer to Wood Mackenzie, on page 140 and the International Energy Agency on page 100. Please provide copies of these source materials to us, appropriately marked to highlight the sections relied upon and cross-referenced to your prospectus. Please also tell us whether these reports and articles are publicly available without cost or at a nominal expense to investors. |
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Response: We acknowledge the Staff’s comment and are supplementally submitting under separate cover copies of the relevant portions of the reports cited in our prospectus. To expedite the Staff’s review, we have clearly marked each report to highlight the applicable portion or section containing the information on which we rely and have included cross references to the appropriate disclosure in Amendment No. 1. We respectfully advise the Staff that, while the information attributable to Wood Mackenzie and the International Energy Agency is not publicly available without cost or at nominal expense to investors, we believe this information provides the most specific and relevant information to potential investors in the Partnership.
| 5. | Please disclose the basis for all your assertions about your competitive position within your industry. If you do not have appropriate independent support for a statement, please revise the language to make clear that this is your belief based upon your experience in the industry, if true. Please also provide independent supplemental materials, with appropriate markings and page references in your responses. The following are examples only of some of your competitive position assertions: |
| • | “We have made significant commitments in downstream transportation and fractionation capacity to ensure access to the most attractive demand markets for our customers,” page 150. |
| • | “The Anadarko basin is one of the most prolific natural-gas producing basins in the United States,” page 140. |
| • | “The basin contains the Cotton Valley sandstone formation, one the of the largest natural gas fields in the continental United States,” page 141. |
| • | “The Barnett Shale play is one of the largest and most mature natural gas fields in North America,” page 141. |
| • | “We are one of the primary midstream operators in each of the natural gas basins in which we conduct business, and also one of the largest producers of NGLs in the United States,” page 150. |
| • | “In addition, we deliver pipeline-quality gas at over 40 locations, including some of the most significant intrastate and interstate pipelines in the U.S. Gulf Coast,” page 160. |
Response: We acknowledge the Staff’s comment and are supplementally submitting under separate cover independent support for our assertions about our competitive position within our industry. To expedite the Staff’s review, we have clearly marked each report to highlight the applicable portion or section containing the information on which
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we rely and have included cross references to the applicable disclosure in Amendment No. 1. In addition, where we do not have appropriate independent support for a statement we have revised our assertions to make clear that they represent our belief based upon our experience in the industry. Please see pages 153 and 163 of Amendment No. 1.
Prospectus Summary, page 1
| 6. | Please balance the discussion of the “Competitive Strengths” of your business with a discussion of your principal competitive challenges and risks. Refer to Securities Act Release No. 33-6900. |
Response: We acknowledge the Staff’s comment and have revised the Registration Statement to include a summary of key risks that are associated with our business and an investment in us. Please see pages 8 and 9 of Amendment No. 1.
| 7. | Please provide additional disclosure to assist readers in understanding why your initial assets consist of a 39%, as opposed to some other percentage, controlling interest in Midcoast Operating given that EEP has indicated a willingness to sell more of its ownership interest in Midcoast Operating in the future. |
Response: We acknowledge the Staff’s comment and respectfully note that, pursuant to the terms of the contribution, conveyance and assignment agreement that we expect to enter into at the closing of this offering, EEP will contribute a 38.999% limited partner interest in Midcoast Operating to us, as well as a 100% limited liability company interest in Midcoast OLP GP, L.L.C., the general partner of Midcoast Operating, which owns an additional 0.001% general partner interest in Midcoast Operating. EEP has determined to contribute an aggregate 39% interest in Midcoast Operating to us because such percentage interest is expected to generate an annual amount of EBITDA and distributable cash flow that EEP believes will be optimal in relation to the size of the offering that EEP intends to pursue at this time. We have revised the Registration Statement to disclose that our initial 39% interest in Midcoast Operating is related to the expected size of the offering. Please see page 9 of Amendment No. 1.
Our Relationship with EEP and Enbridge, page 8
| 8. | Please disclose in this section or in another subheading in the prospectus summary, the amount(s) that your general partner, EEP and Enbridge will receive in conjunction with this offering, including all cash distributions, any payments, compensation, or the value of any equity that the general partner, EEP, Enbridge, or the directors or executive officers of each received or will receive in connection with the offering. |
Response: We acknowledge the Staff’s comment and respectfully advise the Staff that, at the closing of the offering, we will make a distribution to EEP out of the net proceeds of this offering. In addition, we will borrow $350.0 million under our proposed revolving credit facility to fund an additional distribution to EEP. These distributions will be made in partial consideration of EEP’s contribution of assets to us. We undertake to
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provide in future amendments the specific amount of the distribution that will be made to EEP out of the net proceeds of the offering. Please see page 9 of Amendment No. 1. We also undertake to disclose in future amendments the amount of any equity that the general partner, EEP or the directors or executive officers of each will receive in connection with the offering. Enbridge will not directly receive any cash or equity distribution in connection with the offering.
Risk Factors, page 21
Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel, page 37
| 9. | Please expand the risk factor to be more specific to your company and explain and identify the key personnel upon whom you currently depend. In this regard, we note your disclosure on page 179 that you currently have no employees and your general partner is responsible for providing the employees and other personnel necessary to conduct your operations. |
Response: We acknowledge the Staff’s comment and we have expanded this risk factor to be more specific to us and to identify the key personnel upon whom we currently depend. Please see page 38 of Amendment No. 1.
Cash Distribution Policy and Restrictions on Distributions, page 55
Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2012 and the Twelve Months Ended March 31, 2013, page 59
Estimated Distributable Cash Flow for the Twelve Months Ending June 30, 2014, page 62
| 10. | Please explain why you believe the most meaningful period of pro forma estimated cash available for distribution to be the twelve months ending June 30, 2014. Please tell us whether you believe that forecasted distributable cash for the twelve months ending September 30, 2014 would have differed by more than 5% from the existing forecast for the year ended June 30, 2014. |
Response: We acknowledge the Staff’s comment and respectfully advise the Staff that we are in the process of updating our pro forma estimated cash available for distribution and undertake to provide a forecast of distributable cash flow for the twelve months ending September 30, 2014 in a future amendment. In addition, we believe the forecasted distributable cash flow for the twelve months ending September 30, 2014 may increase by more than 5% from the existing forecast for the twelve months ending June 30, 2014 because of: (1) distributions attributable to the Texas Express NGL system, which is expected to commence service during the third quarter of 2013; (2) increases in the volumes of natural gas we expect to deliver on our systems; and (3) improved commodity prices during the third quarter of 2014 compared to the third quarter of 2013.
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| 11. | We note your assumed forecasted volumes on the Anadarko system on page 67 for the twelve months ending June 30, 2014 assumed increased drilling activity would partially offset the known termination of a significant processing contract on the Anadarko system discussed on page 27. Please explain and support how you determined the offsetting increase due to increased drilling activity; which we assume results in 83,000 MMBtu of volume. In this regard, explain how “acreage dedications from existing customers” ensures increased processing volumes of the stated amount. |
Response: We acknowledge the Staff’s comment and respectfully note that our forecasted volumes for the twelve months ending June 30, 2014 for our Anadarko system include approximately 130,000 million British thermal units per day (“MMBtu/d”) of natural gas from the contract that will terminate August 1, 2013. We have estimated the decrease for the period at 90,000 MMBtu/d since we expect this customer will continue to deliver a portion of its produced volumes attributable to this contract to our pipelines through December 31, 2013 under a month-to-month contract. We expect volumes attributable to the terminated contract will decrease by approximately 60,000 MMBtu/d during the month of August 2013, and that the customer will cease delivering any volumes under the new month-to-month contract by January 1, 2014. Over the twelve months ending June 30, 2014, this results in an average decrease of approximately 90,000 MMBtu/d.
During the same period, we expect that other customers will connect, either directly or indirectly through various receipt points, approximately 114 wells to our Anadarko system. To determine the number of wells we expect to connect to our Anadarko system, we examine current rig activity on the acreage surrounding our Anadarko system, assess the impact that current and future natural gas and NGL prices will have on drilling activity and discuss with our customers their current drilling plans. Because the majority of these new wells will be drilled on acreage dedicated to our Anadarko system, natural gas produced by our customers drilling on the acreage must be gathered and processed on our pipeline system. We believe these new wells will offset the natural decline of existing production and replace most of the volumes related to the aforementioned terminated contract.
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| 12. | Please tell us how you calculated the components that make up the net decrease in volumes on your East Texas system. Specifically show us how you calculated the effect on volumes of the gross decrease in dry gas from Haynesville and Bossier and how it was offset by increased drilling in the Cotton Valley formation and its calculated effect on volumes. |
Response: We acknowledge the Staff’s comment and respectfully advise that, for each of our natural gas systems, we calculated the forecasted volume of natural gas gathered and transported for the twelve months ending June 30, 2014 by (i) subtracting the amount we expect production will decrease as a result of the natural production decline curve for each well from the volume of natural gas currently flowing from existing wells connected to the system and (ii) adding the volumes of natural gas we expect to transport and gather from any new wells that we expect will be connected to the system. We use a combination of public data, data from Cawley, Gillespie and Associates and our own measurement data to develop historical production decline curves for these existing wells, which we then use to forecast the declines in the volumes of natural gas produced in the future. The production decline of a Haynesville well is usually steeper than the production decline of a Cotton Valley well, although a Haynesville well typically produces more natural gas both initially and over the production life of the well. As a result, we estimate that a rise in production from wells we expect to be drilled in the Cotton Valley formation will not fully offset the production decline from the wells drilled in the Haynesville formation. The amount of natural gas that we expect to transport or gather from each new well is based on a unique production type curve for each formation and region that is expected to be drilled and the type of well (horizontal or vertical) to be drilled. We work with Cawley Gillespie to develop these production type curves and compare them to the actual realized production success of each of our customers.
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During the twelve months ending June 30, 2014, we expect to connect approximately 50 wells from the Cotton Valley formation and approximately 36 wells from the Haynesville formation to our East Texas system. We estimate that a majority of these wells will connect to our East Texas system during the first six months of 2014. To determine the number of wells we expect to connect to our East Texas system, we examine current rig activity on the acreage surrounding our East Texas system, assess the impact of current and future natural gas and NGL prices will have on drilling activity and discuss with our customers their current drilling plans.
| 13. | Please tell us the reason you are assuming an overall increase in the average NGL content of natural gas to be processed by your systems and your support for such an assumption. Please discuss whether the ability to process increased NGL’s discussed in the first 3 bullet points on pages 67 and 68 combined with the final bullet point in this section is what supports an increase in NGL volumes forecasted for the twelve months ending June 30, 2014. If increased NGL content combined with the ability to process it is not the reason for the increase in forecasted volumes, please revise the discussion. |
Response: We acknowledge the Staff’s comment and respectfully confirm that the increase in forecasted NGL volumes is supported by the four bullet points on pages 68 and 69 of Amendment No. 1. This increase in NGL volumes is primarily attributable to an overall increase in the average NGL content of the natural gas being processed by our systems, as set forth in the bullet point on page 68.
In the current pricing environment, producers are focusing on drilling that produces natural gas with higher NGL content, as the NGLs yield a higher price than the natural gas. The inlet composition of the natural gas being processed at our plants has risen by more than 0.5 gallon of NGLs per 1,000 cubic feet of natural gas (“GPM”) over the last 24 months and is expected to continue to increase as producers target drilling for natural gas with higher GPM. A 0.5 GPM increase in NGL content represents approximately 8,000 to 9,000 barrels per day (“Bpd”) of additional NGLs in the natural gas stream delivered to our processing plants, and our Allison and Ajax plants can extract 90% to 95% of those additional NGLs.
In addition, we further note that our Allison and Ajax plants described in the first bullet point on page 69 are state-of-the-art cryogenic facilities that are capable of extracting more NGLs from the same natural gas than any other processing plants on our systems, which contributes to the overall increase in the average NGL production of our systems. Our Allison and Ajax plants are capable of recovering up to 88% of the ethane contained in the natural gas stream, compared to an average of approximately 70% for our other processing plants. Assuming no increase in either volumes processed or NGL content within the raw natural gas, the Allison and Ajax plants would extract approximately 3,000 more Bpd of ethane than our other processing plants.
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In addition, the forecasted increase in average NGL content disclosed in the third bullet on page 69 of the Registration Statement is based on our assumption that we will extract the maximum volumes of NGLs we are capable of extracting starting in January 2014. However, we are capable of rejecting ethane and leaving it in the natural gas stream when it is more valuable being sold as natural gas than as a stand-alone commodity. We rejected ethane at some of our plants during 2012 and 2013 and have forecasted some ethane rejection during the remainder of 2013. Since late 2012, the majority of our plants on the Anadarko system have rejected ethane because of the lower value of ethane relative to the value of natural gas. Ethane accounts for approximately 10,000 to 12,000 Bpd on our Anadarko system. To the extent the value of ethane is lower relative to the value of natural gas, we will continue to reject ethane on the Anadarko system. Our North Texas and East Texas plants are not currently rejecting ethane because the relative value of ethane to natural gas is higher at these plants. If there is a decrease in the relative value of ethane to natural gas and we believe ethane rejection at our North Texas and East Texas plants will increase our processing margin, we would reduce ethane production by approximately 4,000 to 7,000 Bpd at our plants in these regions. Although we have the operational ability to reject higher amounts of ethane than noted above in all of our operating areas, increased ethane rejection could reduce our recovery of propane and consequently reduce our processing margin.
| 14. | You indicate that you have not forecasted any material change in your contract mix for the twelve months ending June 30, 2014. We assume this statement is intended to convey that the price you receive for volumes forecasted in the table on page 67 will be consistent with pricing obtained in the most recently completed historical period. If so, please indicate the amount of volumes for each major system that are subject to possible change (renewal) in the twelve months ending June 30, 2014. |
Response: We acknowledge the Staff’s comment and respectfully note that our statement on page 68 of the Registration Statement is not intended to convey that we expect that the price we receive for volumes forecasted in the table on page 68 of the Registration Statement will be consistent with pricing obtained in the most recently completed historical period. Instead, we intended to convey that we do not assume any material changes in the balance of our contract mix among fee-based, percentage-of-proceeds, percentage-of-liquids and keep-whole/wellhead purchase contracts and, therefore, our overall direct commodity price exposure. We expect to maintain our current overall level of direct commodity price exposure by maintaining our historical balanced contract mix during the forecast period. We have revised the Registration Statement to clarify this disclosure. Please see page 68 of Amendment No. 1.
| 15. | We note your disclosure on page 68 that the anticipated increase in fee-based segment gross margin is due to expected increases in fees under your existing contracts due to inflation escalators and expected renewals of existing contracts and new contracts under which you will provide fee-based processing services. Please revise to provide |
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| investors with insight into your contract profile including your historical renewal rate, the volume of expiring contracts and the volume of new fee based contracts you anticipate in the 12 months ending June 30, 2014. Alternatively you may present the metrics you believe best illustrates the anticipated forecasted profile of your contract base over the period. |
Response: We acknowledge the Staff’s comment and have revised the Registration Statement to provide investors with insight into our contract profile. Please see page 69 of Amendment No. 1.
Assumptions and Considerations, page 65 Financing, page 71
| 16. | It appears that you will be familiar with the terms of your new credit facility prior to the closing of this offering. If true, upon learning the terms of your new credit facility, please update to include the material terms of the agreement, including the financial covenants you must satisfy prior to making cash distributions. Please also update the first bullet under the heading “Limitations on Cash Distributions and [Your] Ability to Change [Your] Cash Distribution Policy” on page 55 to cross-reference to the discussion of these restrictions. |
Response: We acknowledge the Staff’s comment and respectfully advise the Staff that we are currently negotiating the terms of our proposed new revolving credit facility with potential lenders and that we expect to finalize those terms prior to the commencement of this offering. We undertake to update our disclosure under the section titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility” to reflect the material terms of our new credit facility, including the financial covenants that we must satisfy prior to making cash distributions, once those terms have been agreed to by the parties.
Management’s Discussion and Analysis, page 93
Overview, page 93
| 17. | We believe that your overview could be enhanced to provide a balanced, executive level discussion through the eyes of management that identifies the most important matters upon which management focuses in evaluating financial condition and results of operations and provides a context for the discussion and analysis of your financial statements. It should also serve to inform readers about how you earn revenue and income and generate cash and provide insight into material opportunities, challenges and risks as well as actions you are taking to address those material opportunities, challenges and risks. Therefore, in future filings please give consideration to providing. |
| • | An identification and discussion of key variables and other quantitative and qualitative factors necessary for an understanding and evaluation of your business and a discussion of management’s view of the implications and significance of the information, such as the volatility in gas prices and the impact such volatility has on your contracts with commodity price exposure; and |
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| • | A discussion and analysis of material uncertainties and known trends that would cause reported financial information not to be necessarily indicative of future operating performance or financial condition to promote an understanding of the quality and potential variability of your earnings and cash flows, such as the “significant processing contract on your Anadarko system that will terminate in the third quarter of 2013.” |
Response: We acknowledge the Staff’s comment and the Registration Statement has been revised as requested. Please see page 94 of Amendment No. 1.
Items Affecting the Comparability of Our Financial Results, page 98
| 18. | We note your disclosure that you estimate that your proportionate share of annual expenses related to the financial support agreement will be approximately $2.0 million and that EEP has “historically provided such financial support to Midcoast Operating at no cost.” Please discuss the risks, if any, that EEP will not provide financial support at no cost in the future. |
Response: We acknowledge the Staff’s comment. Following the completion of the offering, EEP will no longer provide financial support to Midcoast Operating at no cost, and we will be responsible for our proportionate share of Midcoast Operating’s annual expenses attributable to the financial support agreement. We have revised the Registration Statement to clarify our financial support arrangement with EEP. Please see page 100 of Amendment No. 1. For a discussion of the risks we would face if EEP were to no longer provide any financial support to Midcoast Operating, please see page 32 of Amendment No. 1.
Liquidity and Capital Resources, page 113
| 19. | We note your disclosure that you will enter into an intercorporate services agreement with EEP at the closing of this offering that will reduce total general and administrative expenses by $25 million annually. Please disclose the total amount of expenses payable by your partnership under this agreement and any material terms or provisions. |
Response: We acknowledge the Staff’s comment and respectfully advise the Staff that we are currently finalizing the terms of our proposed intercorporate services agreement with EEP and we expect that to be completed prior to the commencement of this offering. We hereby undertake to update our disclosure to reflect the material terms of the intercorporate services agreement after those terms have been agreed upon by the parties. We note that, on a pro forma basis, for the year ended December 31, 2012 and the three months ended March 31, 2013, we expect that Midcoast Operating would have paid
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approximately $80.1 million and $18.2 million, respectively, in general and administrative expenses, which amounts have been reduced by $25.0 million and $6.3 million, respectively, pursuant to the proposed terms of the intercorporate services agreement. Please see the general and administrative line item on pages F-4 and F-5 of Amendment No. 1.
Capital Expenditures, page 114
| 20. | We note your disclosure that “if EEP elects not to fund any expansion capital expenditures at Midcoast Operation, [you] will have the opportunity to fund all or a portion of EEP’s proportionate share of such expansion capital expenditures in exchange for additional interest in Midcoast Operating.” Please discuss in this section that you currently have no agreements and EEP is not obligated to sell any additional interest in Midcoast Operation. In this regard, we note your disclosure on page 101 that “EEP is under no obligation to offer to sell us additional interest in Midcoast Operating.” Please also tell us how expansion capital expenses will be met if EEP elects not to fund such expenses and you also elect not to fund EEPs’ share. |
Response: We acknowledge the Staff’s comment and have revised our disclosure to reflect the fact that EEP is not obligated to sell to us, and we currently have no agreements with EEP to purchase, any additional interests in Midcoast Operating, and we do not know when or if any such additional interests will be offered to us to purchase. Please see pages 6, 7, 28, 102, 151, 153 and 216 of Amendment No. 1. We have further revised our disclosure to note that, in the event that EEP elects not to fund its share of the expansion capital expenditures and we elect not to fund EEP’s share, we expect that Midcoast Operating will not pursue the capital projects associated with such unfunded capital expenditures. Please see page 115 of Amendment No. 1.
Summary of Obligations and Commitments, page 115
| 21. | In an appropriate place in your disclosure, please explain why your obligations associated with your Transportation/Service contracts increase dramatically in 2017. |
Response: We have revised the Registration Statement accordingly. Please see page 116 of Amendment No. 1.
Operating Activities, page 116
| 22. | Please provide a more informative analysis and discussion of cash flows from operating activities, including changes in working capital components, for each period presented. In doing so, please explain the underlying reasons and implications of material changes between periods to provide investors with an understanding of trends and variability in cash flows. Please refer to Item 303(a) of Regulation S-K and SEC Release No. 33-8350. |
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Response: We have revised the Registration Statement accordingly. Please see pages 117 through 122 of Amendment No. 1.
Business, page 143
| 23. | We note your disclosure of new expansion capital expenditures. Please discuss any pending government permits or licenses related to these new projects. In this regard, we note your disclosure of the new Beckville processing plant in East Texas, the construction of numerous compressor station projects, pipeline laterals and NGL laterals, on page 70 and the completion of the Texas Express NGL system, on page 71. |
Response: We acknowledge the Staff’s comment and respectfully note that the Beckville plant is being designed so that the facility will be covered by a standard air permit granted by the Texas Commission on Environmental Quality (“TCEQ”). Once the final design is obtained and the permit is filed, we expect the permit will be granted within 45 days. The compressor stations are at a relatively low level of emission and will be permitted under a “Permit by Rule” in Texas by the TCEQ, which simply requires a notification to the state within ten days of the start of construction. In Oklahoma, we file for a General Permit which requires a Notice of Intent (“NOI”), and construction can begin with proof that the NOI has been received by the Oklahoma Department of Environmental Quality. The pipelines described in the filing are all interstate pipelines which do not require pre-approvals prior to beginning construction or operations. There are no government licenses or permits pending in connection with the planned commencement of service on the Texas Express NGL system in the third quarter of 2013.
Business Strategies, page 148
| 24. | We note your indication here and elsewhere in your registration statement that you have acquisition opportunities available to you in the future such as the remaining ownership interests in Midcoast Operating held by EEP. Because it appears that you do not know when such interests will be, if ever, offered to you to purchase, please state as much. Please also highlight the inherent conflicts of interest associated with such offer, considering you share the same executive officers. |
Response: We have revised the Registration Statement as requested. Please see pages 6, 7, 28, 102, 151 and 153 of Amendment No. 1. We have also revised our disclosure to highlight that any such offer may constitute a conflict of interest that will be resolved by our general partner in accordance with our partnership agreement. Please see page 216 of Amendment No. 1.
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Competitive Strengths, page 149
| 25. | We note your disclosure on page 7, and 149 that one of your competitive strengths is that you have “strategically located assets in prolific natural gas-producing basins with unconventional resources plays and access to major market hubs.” We further note your statement on page 139 that “natural gas production from the major shale formation will provide the majority of the growth in domestically produced natural gas supply in coming years, increasing to approximately 50% in 2040 as compared with 34% in 2011.” Please provide us with the supporting documentation for these statements. |
Response: We acknowledge the Staff’s comment and are supplementally submitting under separate cover supporting documentation for the above-referenced statements in the Registration Statement.
Our Partnership Agreement, page 224
| 26. | We note your disclosure throughout the registration statement that you have entered into joint ventures. Please further discuss if the terms of the partnership agreement allow you to engage in joint ventures and disclose any activities that you may engage through a joint venture that you could not otherwise undertake. Please refer to Section II.B.2.f of Securities Act Release 33-6900 (June 17, 1991). |
Response: We acknowledge the Staff’s comment and have carefully considered Securities Act Release 33-6900. Under the terms of the partnership agreement that we will enter into upon the completion of the offering, there are no restrictions on our ability to engage in joint ventures. In addition, we further note that, under our partnership agreement, we may engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law;provided,however, that we may not engage in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.
Item 17. Undertakings
| 27. | Please provide the undertakings set forth at Item 512(a)(6) of Regulation S-K. |
Response: We acknowledge the Staff’s comment and have revised the Registration Statement accordingly. Please see page II-3 of Amendment No. 1.
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Consolidated Financial Statements
Unaudited Pro Forma Consolidated Financial Statements, page F-2
| 28. | We note your disclosure on page 194 that no specific amounts of NEO compensation was allocated to you for 2012, 2011 or 2010. You also state on page 194 that you will be charged for the services of executive management resident in the U.S. Please advise whether the estimate of incremental general and administrative expenses includes the future allocation of the cost of executive management. If not, please advise whether a portion of NEO costs should be reflected in the pro forma financial statements assuming no allocation was made to the predecessor. If no allocation was made to the predecessor, please explain your basis for excluding a cost of doing business of the predecessor. Please likewise advise how you reflected the cost of financial support provided to the predecessor and whether an adjustment is necessary. |
Response: While no specific amounts of NEO compensation were allocated to us for 2012, 2011 or 2010, specific amounts of NEO compensation were allocated to our predecessor that were reflected in the financial statements included in the Registration Statement. As such, those allocated amounts are also reflected in the pro forma financial statements included in the Registration Statement and, therefore, no additional adjustments are required.
As a part of EEP, which is a much larger, investment grade-rated organization, our predecessor did not incur and was not allocated costs for financial support. The costs that Midcoast Operating will incur pursuant to the terms of the financial support agreement following the consummation of the offering will be based on the cumulative average annual amount of letters of credit and guarantees that EEP will provide for the benefit of Midcoast Operating. Midcoast Operating does not have a credit rating and will not have one at the time of the closing of the offering. As a result, we cannot know with reasonable precision the cumulative average annual amount of letters of credit and guarantees that EEP will have to provide for the benefit of Midcoast Operating. Under Rule 11-02(b)(6) of Regulation S-X, we do not believe a factually supportable pro forma adjustment for the financial support arrangement can be calculated and, therefore, disclosed, based on an estimate of such amounts, which would in turn be based upon an assumed credit rating.
Unaudited Pro Forma Consolidated Statements of Financial Position, page F-6
| 29. | Please expand your equity section to disclose the number of equity units authorized and outstanding by class on a pro forma basis. Revise your disclosure accordingly. Reference is made to SAB Topic 4:F. |
Response: We acknowledge the Staff’s comment and will undertake to disclose the number of equity units that will be outstanding in a future amendment to the Registration Statement that includes the number of common units and subordinated units to be issued and outstanding following the closing of the offering. Please read page F-6 of
Securities and Exchange Commission
August 7, 2013
Page 16
Amendment No. 1. We respectfully note that our partnership agreement will authorize us to issue an unlimited number of additional units or other equity interests for the consideration and on the terms and conditions determined by our general partner without the approval of our unitholders, as described under the caption “Issuance of Additional Securities” on page 230 of Amendment No. 1.
Notes to Unaudited Financial Statements, page F-7
| 30. | We assume adjustment (b) on page F-7 relates to the $350 million assumed proceeds from to-be-obtained credit facilities, the proceeds of which will be distributed to EEP as depicted in adjustment (f). If so, please supplementally explain why assumed interest on such borrowings would be reduced by capitalized interest relating to construction of assets. Specifically tell us what additional pro forma adjustments would have been made had you assumed the full cost of the interest expense on the assumed proceeds. Please also advise whether the terms of the Partnership’s revolving credit facility have been finalized. If so, please disclose your assumptions as to interest rate and fees. If the facility has yet to be executed, please advise why you believe such adjustment is factually supportable. |
Response: We acknowledge the Staff’s comment and respectfully advise the Staff that the assumed interest expense on the $350 million assumed proceeds from the to-be-obtained credit facility, presented as pro forma adjustment (b), has not been reduced by capitalized interest relating to the construction of assets. We have removed from footnote (b) the discussion of capitalized interest which relates specifically to the predecessor financial statements rather than the pro forma adjustment. Please see page F-7 of Amendment No. 1.
As noted above in our response to Comment 16, we are currently negotiating the terms of our proposed new revolving credit facility with the potential lenders and we expect to finalize those terms prior to the commencement of this offering. We believe an adjustment for interest expense to be factually supportable based on our intention of having fully executed the revolving credit facility prior to the commencement of this offering.
| 31. | We note the intercorporate services agreement will continue the allocation methodology in existence with Midcoast Operating LP prior to the agreement. The disclosure of the methodology in Midcoast Operating LP’s financial statements indicates it is a cost allocation method. Please tell us how you intend to treat the $25 million reduction of general and administrative costs in future financial statements. If you intend to reflect the subsidy as a reduction in expense, as opposed to a capital transaction, please tell us how it reflects a negative cost of doing business. See Question 1 of SAB 1:B.1. Please also provide an estimate of what the cost would have been on a stand-alone basis had Midcoast been operated as an unaffiliated entity. |
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August 7, 2013
Page 17
Response: We acknowledge the Staff’s comment. We intend to treat the $25 million reduction of general and administrative costs in future financial statements as a reduction to the general and administrative cost allocation computed pursuant to the existing allocation methodology, to the extent such computed allocation is not less than $25 million. As envisioned, EEP will continue to compute the allocation of general and administrative costs pursuant to its existing allocation methodology; however, EEP will exclude $25 million from the amounts that would otherwise be allocated to Midcoast Operating, L.P., to the extent the excluded amount does not reduce the expense below zero. The “negative cost” (cost reduction) we have adjusted in our calculations represents the approximate amount of certain indirect costs allocated to EEP for its natural gas business from Enbridge Inc.
As described in the Registration Statement, following the closing of the offering, the Partnership will control Midcoast Operating, L.P. through its ownership of the general partner of Midcoast Operating, L.P., while EEP will continue to own a significant limited partner interest in the Partnership and will also control the Partnership through EEP’s ownership of the general partner of the Partnership. EEP will consolidate the financial results of the Partnership and its subsidiaries, including Midcoast Operating, L.P., in EEP’s consolidated financial statements. As a result, EEP will retain the ultimate obligation for these expenses rather than allocating the costs to Midcoast Operating, L.P. Consequently, Midcoast Operating, L.P. will expense the amount charged to it by EEP. Given the nature of these costs, it is not practicable for us to estimate what these costs would have been on a stand-alone basis.
Midcoast Operating, L.P. Notes to the Consolidated Financial Statements
Note 1. Organization and Nature of Operations, page F-17
| 32. | For our understanding, please contrast the accounting for maintenance versus expansion capital expenditures. We assume maintenance capital expenditures are expensed as incurred and expansion capital expenditures are capitalized. To the extent any portion of maintenance capital expenditures are capitalized, please explain the nature of such expenditures in detail including the basis for capitalization. To the extent any portion of expansion capital expenditures are expensed, please explain the nature of such expenditures. |
Response: We acknowledge the Staff’s comment and respectfully refer the Staff to our disclosure of expansion capital expenditures and maintenance capital expenditures on page 77 of Amendment No. 1.
Maintenance capital expenditures are cash payments made to maintain our asset base, operating capacity or operating income, or to maintain the existing useful life of any of our capital assets, in each case over the long term. By contrast, expansion capital expenditures are cash payments incurred for acquisitions or capital improvements that we expect will increase our asset base, operating capacity or operating income over the long term or meaningfully extend the useful life of any of our capital assets.
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August 7, 2013
Page 18
For example, the purchase of a new compressor to provide additional compression on a gathering line to increase the volumes of natural gas to be gathered is an expansion capital expenditure. However, the cost to perform a zero-hour overhaul of an existing compressor is a maintenance capital expenditure because the useful life of the compressor has been maintained over the long term. In each case, the amounts paid are capitalized as property, plant and equipment, but in the first case the payment relates to the expansion of services over the long term and in the latter case the payment relates to maintaining over the long term a level of service currently being provided.
Although the payments are capitalized in each case, maintenance capital expenditures and expansion capital expenditures are treated differently under our partnership agreement for purposes of determining operating surplus and the character of our cash distributions.
In contrast to maintenance capital expenditures, maintenance costs do not provide a long-term benefit to the partnership (such as the repair of a compressor that is not working properly) and are treated as operating expenditures as incurred, rather than capitalized.
Note 2. Summary of Significant Accounting Policies, F-19
| 33. | You state on page F-23 that you recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market price or present value techniques. Your disclosure suggests that impairment would be recognized in situations where undiscounted cash flows exceed the carrying amount but the fair value of the underlying asset is below carrying value. If so, please advise how this policy conforms with GAAP. |
Response: We acknowledge the Staff’s comment and have revised the Registration Statement to clarify the method we employ to evaluate the recoverability of our property, plant and equipment. Please see pages F-25 and F-26 of Amendment No. 1.
Note 7. Intangibles, page F-30
| 34. | Please explain to us the nature of contributions you have made in aid of construction activities and why such contributions would constitute an intangible asset as opposed to an expense. Please be detailed in your explanation of the nature of the intangible right obtained. |
Response: We respectfully advise the Staff that our contributions in aid of construction are predominantly comprised of contributions to third-party natural gas and NGL pipeline companies to cover the costs of connecting our gathering and transmission pipelines to those companies’ pipelines. For legal reasons, the owners of the third-party natural gas and NGL pipelines will not allow us or any other company to perform construction activity to connect a pipeline to their pipelines, but will typically perform the construction on our or another company’s behalf for a one-time payment to cover the construction costs. In connection with the one-time payment we pay to a third-party pipeline company to cover such construction costs, we enter into a contractual agreement
Securities and Exchange Commission
August 7, 2013
Page 19
setting forth the terms that grant us the right to use the pipeline connection for a certain period of years, which varies by contract. Pursuant to the guidance included in ASC 350-30-25-1 and ASC 350-30-30-1, with reference to ASC 805-50-30-2, we have recognized an intangible asset measured by the amount of cash paid for the pipeline connection, which we amortize to expense over the period we expect to benefit from the pipeline connection. We also considered analogous recognition criteria set forth in ASC 805-20-25 and, in particular, ASC 805-20-55-37 regarding “Use Rights,” which would support our recognition of these costs as intangible assets, because we are granted the right to access pursuant to a contractual arrangement with the third-party pipeline owner. The access to natural gas and NGL pipelines and market delivery locations to which these pipelines connect is the intangible right we receive in connection with our contributions in aid of construction.
We benefit from making the contribution over a period of several years as a result of the connections we make to these third-party natural gas and NGL pipelines, which provide us and our customers with access to numerous market centers at which we can sell the natural gas and NGLs derived from our operations. Additionally, these connections to third-party natural gas and NGL pipelines help us to attract new customers due to the increased market access available as a result of our third-party pipeline connections. The long-term benefit provided by these contributions is properly represented as an asset rather than as an expense, since the benefit period exceeds the current period and should therefore not be considered a period expense. We believe the ongoing future benefit we receive as a result of these contributions in aid of construction contracts are best characterized as intangible assets because the pipeline connections provide probable future economic benefits that will contribute to future net cash inflows as a result of the contractual rights we received to flow natural gas and NGLs to the third-party pipeline, which are the result of past transactions or events. For these reasons, we believe the capitalization of these costs and presentation as intangible assets on our consolidated statements of financial position is appropriate.
Note 8. Related Party Transactions, page F-31
| 35. | We note your disclosure on page F-32 of the total amounts reimbursed for each period presented through EEP for services rendered pursuant to the general and administrative services agreement. Please revise your filing to explicitly reflect these amounts on the face of your financial statements as required by 4-08(k) of Regulation S-X. |
Response: We acknowledge the Staff’s comment and respectfully advise that we have applied the requirements of Rule 4-08(k) as they relate to the statements of financial position and cash flows. With respect to the statements of income, we respectfully note that we have included comprehensive qualitative and quantitative disclosure regarding all material related party transactions in the footnotes to the financial statements and have revised such footnotes to reflect the total amounts incurred and included in each respective income statement line item for affiliate transactions and for services rendered pursuant to our historical general and administrative services agreement with EEP. Please refer to pages F-33 and F-61 of Amendment No. 1.
Securities and Exchange Commission
August 7, 2013
Page 20
Although we acknowledge that Rule 4-08(k) of Regulation S-X requires that the dollar amount of all material related party transactions be disclosed on the face of the financial statements, we believe that our comprehensive footnote disclosure is sufficiently informative and provides a higher degree of transparency into our related party transactions, both qualitatively and quantitatively. We further believe that presenting separate captions for related party transactions on the operating revenue, cost of natural gas and NGLs, operating and maintenance, and general and administrative line items on the statements of income would not materially enhance our existing disclosure.
Furthermore, we have noted diversity in practice with respect to the application of the requirements of Rule 4-08(k) as they relate to the statements of income among many companies in our peer group, as well as other companies in our industry. In that regard, we reviewed the financial statements of 22 publicly traded partnerships and noted that only six of the 22 included separate captions for related party transactions on the face of their statements of income.
Midcoast Operating, L.P. Consolidated Statements of Financial Position, page F-56
| 36. | We note your supplemental pro forma information related to the anticipated distribution to EEP based on the guidance from SAB Topic 1B:3. Please tell us what consideration you gave to providing pro forma per unit data within your historical financial statements based on the number of units necessary to be issued to the produce net proceeds to replace the distribution. |
Response: We considered the guidance in SAB Topic 1B:3, the related guidance in the Staff’s Financial Reporting Manual (sections 3420 and 3430) and Discussion Document C from the SEC Regulations Committee meeting on April 17, 2007. In response to the Staff’s comment, once the number of common units to be issued at the closing of the offering and related pro forma per unit data are determined, the Partnership will disclose pro forma per unit data giving effect to the number of common units whose proceeds would be necessary to pay the distribution to EEP. Since the entire amount of net proceeds from the offering and the new revolving credit facility will be used to fund a distribution to EEP, the pro forma number of common units used in the denominator will be the same as if the Partnership were to assume that the distribution was funded with proceeds from the issuance of new common units per SAB Topic 1B:3. Please refer to page F-6 of Amendment No. 1.
We hereby acknowledge the Staff’s closing comments to the letter and hereby undertake to comply with the Staff’s requests. Please direct any questions or comments regarding the foregoing to the undersigned or to our counsel at Latham & Watkins LLP, Bill Finnegan at (713) 546-7410 or Brett Braden at (713) 546-7412.
| Very truly yours, | ||
| MIDCOAST ENERGY PARTNERS, L.P. | ||
| By: | Midcoast Holdings, L.L.C., its general partner | |
| By: | /s/ Mark A. Maki | |
| Mark A. Maki | ||
| President | ||
| cc: | Jennifer López, Securities and Exchange Commission |
| Jim Allegretto, Securities and Exchange Commission |
| Jason Niethamer, Securities and Exchange Commission |
| Bill Finnegan, Latham & Watkins LLP |
| Brett Braden, Latham & Watkins LLP |
| Joshua Davidson, Baker Botts L.L.P. |
| Tull R. Florey, Baker Botts L.L.P. |
