Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K 1Q15 RECAST - Summit Midstream Partners, LP | a1q15recastform8-k.htm |
| EX-99.1 - 1Q15 RECAST FORM 10-Q FINANCIALS - Summit Midstream Partners, LP | ex991-115recastfina.htm |
EXHIBIT 99.2
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
This Management’s Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") is intended to inform the reader about matters affecting the financial condition and results of operations of SMLP and its subsidiaries for the period since December 31, 2014. As a result, the following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included in this report and the MD&A and the audited consolidated financial statements and related notes that are included in the 2014 Annual Report. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements in this report. Actual results may differ materially from those contained in any forward-looking statements.
MD&A comprises the following sections:
• | Overview |
• | Trends and Outlook |
• | How We Evaluate Our Operations |
• | Results of Operations |
• | Non-GAAP Financial Measures |
• | Liquidity and Capital Resources |
• | Critical Accounting Estimates |
Overview
We are a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. Our gathering systems and the unconventional resource basins in which they operate are as follows:
• | Mountaineer Midstream, a natural gas gathering system located in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia; |
• | Bison Midstream, an associated natural gas gathering system located in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; |
• | Polar and Divide, a crude oil and produced water gathering system and transmission pipelines (under development) located in the Williston Basin; |
• | DFW Midstream, a natural gas gathering system located in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and |
• | Grand River Gathering, a natural gas gathering and processing system located in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah. |
We believe that our gathering systems are well positioned to capture volumes from producer activity in these regions in the future.
We provide natural gas gathering, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term and fee-based gathering and processing agreements with our customers and counterparties. We contract with producers to gather natural gas from pad sites, wells and central receipt points connected to our systems. We then compress, dehydrate, treat and/or process these volumes for delivery to downstream pipelines for ultimate delivery to third-party processing plants and/or end users. We also contract with producers to gather crude oil and produced water from wells connected to our systems for delivery to third-party rail terminals in the case of crude oil and to third-party disposal facilities in the case of produced water.
Our results are driven primarily by the volumes that we gather, treat and/or process. We generate the majority of our revenue from the natural gas gathering, treating and processing services that we provide to our natural gas
EX 99.2-1
EXHIBIT 99.2
producer customers. Under the substantial majority of these agreements, we are paid a fixed fee based on the volumes we gather, treat and/or process. These agreements enhance the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn revenue from (i) crude oil and produced water gathering, (ii) our marketing of natural gas and natural gas liquids, (iii) the sale of physical natural gas purchased from our customers under percentage-of-proceeds and keep-whole arrangements, and (iv) from the sale of condensate retained from our gathering services at Grand River Gathering. We can be exposed to commodity price risk from engaging in any of these additional activities with the exception of produced water gathering.
We also have indirect exposure to changes in commodity prices in that persistent low commodity prices may cause our customers to delay drilling or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If our customers delay drilling or temporarily shut-in production, our MVCs ensure that we will receive a certain amount of revenue from our customers.
Most of our gathering agreements are underpinned by areas of mutual interest ("AMIs") and MVCs. Our AMIs cover over 1.6 million acres in the aggregate and provide that any production from wells drilled by our customers within the AMI will be shipped on our gathering systems. Our MVCs, which totaled 3.9 trillion cubic feet equivalent ("Tcfe," determined using a ratio of six Mcf of gas to one barrel ("Bbl") of oil) at March 31, 2015 and average approximately 1.3 Bcfe/d through 2019, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any MVC shortfall. Our MVCs had a weighted-average remaining life of 9.1 years as of March 31, 2015, assuming minimum throughput volumes for the remainder of the term.
Trends and Outlook
Our business has been, and we expect our future business to continue to be, affected by the following key trends:
• | Acquisitions from Summit Investments and third parties; |
• | Natural gas, NGL and crude oil supply and demand dynamics; |
• | Growth in production from U.S. shale plays; |
• | Capital markets activity and cost of capital; and |
• | Shifts in operating costs and inflation. |
In connection with the Polar and Divide Drop Down, our exposure to crude oil supply and demand dynamics has increased. Our expectations regarding any of the above trends are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. For additional information, see the "Trends and Outlook" section of MD&A included in the 2014 Annual Report.
How We Evaluate Our Operations
We conduct and report our operations in the midstream energy industry through five reportable segments:
• | the Marcellus Shale, which is served by Mountaineer Midstream; |
• | the Williston Basin – Gas, which is served by Bison Midstream; |
• | the Williston Basin – Liquids, which is served by Polar and Divide; |
• | the Barnett Shale, which is served by DFW Midstream; and |
• | the Piceance Basin, which is served by Grand River Gathering. |
Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance. We view these metrics as important factors in evaluating our profitability and review these measurements on a regular basis for consistency and trend analysis. These metrics include:
• | throughput volume, |
• | revenues, |
• | operation and maintenance expenses, |
EX 99.2-2
EXHIBIT 99.2
• | EBITDA, |
• | adjusted EBITDA and segment adjusted EBITDA, and |
• | distributable cash flow. |
There have been no changes in the composition or characteristics of these metrics during the three months ended March 31, 2015, except as noted below.
Throughput Volume
The volume of (i) natural gas that we gather, treat and/or process and (ii) crude oil and produced water that we gather depends on the level of production from natural gas or crude oil wells connected to our gathering systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity. Furthermore, because the production rate of natural gas and crude oil wells decline over time, production can only be maintained or increased by new drilling or other activity.
As a result, we must continually obtain new supplies of production to maintain or increase the throughput volume on our systems. Our ability to maintain or increase throughput volumes from existing customers and obtain new customers and counterparties is impacted by:
• | successful drilling activity within our areas of mutual interest; |
• | the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected; |
• | the number of new pad sites in our areas of mutual interest awaiting connections; |
• | our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing areas of mutual interest; and |
• | our ability to gather, treat and/or process production that has been released from commitments with our competitors. |
Following the Polar and Divide Drop Down, we will continue to report volumes for natural gas gathering and will now also report volumes for crude oil and produced water gathering. Crude oil and produced water gathering are aggregated and reported as "liquids" gathering and measured in thousands of barrels per day ("Mbbl/d"). Gathering rates are reported in barrels.
Revenues
Our revenues are primarily attributable to the volumes that we gather, treat and/or process and the rates we charge for those services. A substantial majority of our gathering and processing agreements are fee-based, which limits our direct commodity price exposure. We also have percent-of-proceeds and keep-whole arrangements under which the gathering and processing revenues that we earn correlate directly with the fluctuating price of natural gas, condensate and NGLs.
Many of our gathering and processing agreements contain MVCs pursuant to which our customers agree to ship or process a minimum volume of production on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. These MVCs support our revenues and serve to mitigate the financial impact associated with declining volumes.
Certain revenue reclassifications have been made to prior-year amounts to conform to the current-year presentation. We evaluated our classification of revenues and concluded that creating an “other revenues” category would provide reporting that was more reflective of our results of operations and how we manage our business. As such, certain revenue transactions that previously represented the “and other” portions of (i) gathering services and (ii) natural gas, NGLs and condensate sales have been reclassified to other revenues. Other revenues largely comprises electricity pass-throughs for customers of Bison Midstream and Grand River Gathering and connection fees on the Polar and Divide system. Other revenues also includes the amortization expense associated with our favorable and unfavorable gas gathering contracts. These reclassifications had no impact on total revenues, net income or total partners' capital.
Subsequent to the reclassification, revenues are recognized as follows:
• | Gathering services and related fees. Revenue earned from the gathering, treating and processing services that we provide to our natural gas and crude oil producer customers. |
EX 99.2-3
EXHIBIT 99.2
• | Natural gas, NGLs and condensate sales. Revenue earned from (i) the sale of physical natural gas and natural gas liquids purchased from our customers under percentage-of-proceeds and keep-whole arrangements with certain of our customers on the Bison Midstream and Red Rock gathering systems, (ii) the sale of natural gas we retain from our DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. |
• | Other revenues. Revenue earned primarily from (i) electricity costs for which our Bison Midstream and Grand River Gathering customers have agreed to reimburse us and (ii) connection fees for customers of the Polar and Divide system. |
For additional information on our reportable segments and how the other metrics noted above help us manage our business, see Note 3 to the unaudited condensed consolidated financial statements and the "How We Evaluate Our Operations" section of MD&A included in the 2014 Annual Report.
EX 99.2-4
EXHIBIT 99.2
Results of Operations
Consolidated Overview of the Three Months Ended March 31, 2015 and 2014
The following table presents certain consolidated and other financial and operating data as of or for the periods indicated.
Three months ended March 31, | |||||||
2015 | 2014 | ||||||
(Dollars in thousands, except fee-rate data) | |||||||
Revenues: | |||||||
Gathering services and related fees | $ | 60,767 | $ | 49,903 | |||
Natural gas, NGLs and condensate sales | 12,613 | 26,304 | |||||
Other revenues | 3,781 | 3,174 | |||||
Total revenues | 77,161 | 79,381 | |||||
Costs and expenses: | |||||||
Cost of natural gas and NGLs | 5,384 | 14,353 | |||||
Operation and maintenance | 21,057 | 21,832 | |||||
General and administrative | 9,658 | 9,053 | |||||
Transaction costs | — | 537 | |||||
Depreciation and amortization | 23,755 | 20,379 | |||||
Total costs and expenses | 59,854 | 66,154 | |||||
Other income | 1 | 1 | |||||
Interest expense | (12,118 | ) | (7,144 | ) | |||
Income before income taxes | 5,190 | 6,084 | |||||
Income tax expense | (177 | ) | (159 | ) | |||
Net income | $ | 5,013 | $ | 5,925 | |||
Other Financial Data: | |||||||
EBITDA (1) | $ | 41,313 | $ | 33,832 | |||
Adjusted EBITDA (1) | 55,050 | 46,993 | |||||
Capital expenditures (2) | 25,188 | 53,580 | |||||
Acquisitions of gathering systems (3) | 2,941 | 305,000 | |||||
Distributable cash flow (1)(2) | 40,926 | 33,602 | |||||
Operating Data: | |||||||
Miles of pipeline as of March 31 | 2,645 | 2,451 | |||||
Aggregate average throughput – gas (MMcf/d) | 1,583 | 1,311 | |||||
Aggregate average throughput rate per Mcf – gas | $ | 0.40 | $ | 0.44 | |||
Average throughput – liquids (Mbbl/d) | 59.9 | 29.1 | |||||
Average throughput rate per Bbl – liquids | $ | 1.43 | $ | 1.06 | |||
__________
(1) See "Non-GAAP Financial Measures" herein for additional information on EBITDA, adjusted EBITDA and distributable cash flow as well as their reconciliations to the most directly comparable GAAP financial measure.
(2) See "Liquidity and Capital Resources" herein for additional information on capital expenditures.
(3) Reflects cash paid (including working capital and capital expenditure adjustments) and value of units issued, if any, to fund acquisitions and/or drop downs. For additional information, see Note 15 to the unaudited condensed consolidated financial statements.
Volumes – Gas. For the three months ended March 31, 2015, our aggregate throughput volumes increased to an average of 1,583 MMcf/d, compared with an average of 1,311 MMcf/d for the three months ended March 31, 2014.
EX 99.2-5
EXHIBIT 99.2
The increase in volume throughput largely reflects the contribution from the Mountaineer Midstream and DFW Midstream systems, partially offset by volume throughput declines on the Grand River Gathering system.
Volumes – Liquids. Average daily throughput for crude oil and produced water increased to 59.9 Mbbl/d for the three months ended March 31, 2015, compared with an average of 29.1 Mbbl/d in the prior-year period. The increase in crude oil and produced water volume throughput primarily reflects the continued development of the Polar and Divide system, new pad site connections and producers' ongoing drilling activity.
Revenues. For the three months ended March 31, 2015, total revenues decreased $2.2 million, or 3%. The decrease in total revenues reflects a decline in natural gas, NGLs and condensate sales and other for Bison Midstream, Grand River Gathering and DFW Midstream, partially offset by an increase in gathering services and other fees across all gathering systems.
Gathering Services and Related Fees. The increase in gathering services and related fees during the three months ended March 31, 2015 was primarily driven by higher volume throughput on the Polar and Divide, DFW Midstream and Mountaineer Midstream systems. The aggregate average throughput rate for gas decreased to $0.40 per Mcf during the three months ended March 31, 2015, compared with $0.44 per Mcf in the prior-year period primarily as a result of a larger proportion of gathering fee revenue from Mountaineer Midstream. The average throughput rate for crude oil and produced water increased to $1.43 per Bbl during the three months ended March 31, 2015, compared with $1.06 per Bbl in the prior-year period primarily as a result of contract amendments in 2014 which increased gathering rates in connection with our commitment to further expand the Polar and Divide system.
Natural Gas, NGLs and Condensate Sales. The decrease in natural gas, NGLs and condensate sales for the three months ended March 31, 2015 was primarily a result of the impact of declining commodity prices, partially offset by an increase in volumes on the Bison Midstream and Grand River Gathering systems that are subject to percent-of-proceeds arrangements. Declining commodity prices negatively impacted our percent-of-proceeds arrangements at Bison Midstream and Grand River Gathering, our fuel retainage revenue at DFW Midstream and condensate revenue for Grand River Gathering.
Costs and Expenses. For the three months ended March 31, 2015, total costs and expenses decreased $6.3 million, or 10%, primarily due to a decrease in cost of natural gas and NGLs at Bison Midstream and Grand River Gathering and a decrease in operation and maintenance at each of our gathering systems, except Polar and Divide. These lower expenses were partially offset by increased operation and maintenance and general and administrative expenses for Polar and Divide as well as an increase in depreciation and amortization across all of our gathering systems.
Cost of Natural Gas and NGLs. The decrease in cost of natural gas and NGLs during the three months ended March 31, 2015 was largely driven by declining commodity prices and the associated impact on our percent-of-proceeds arrangements at Bison Midstream and Grand River Gathering. This impact was partially offset by an increase in volume throughput for these arrangements.
Operation and Maintenance. Operation and maintenance expense decreased during the three months ended March 31, 2015 primarily as a result of lower-cost electricity and a decline in third-party natural gas treating expenses for DFW Midstream, partially offset by an overall increase in compensation-related expenses and an increase in connection fee pass-through expense for Polar and Divide as a result of system expansion (the revenue component of which is recognized in other revenues).
General and Administrative. General and administrative expense increased during the three months ended March 31, 2015 largely as a result of an increase in salaries, benefits and incentive compensation and professional services fees.
Transaction Costs. Transaction costs recognized during the three months ended March 31, 2014 primarily relate to financial and legal advisory costs associated with the Red Rock Drop Down.
Depreciation and Amortization. The increase in depreciation and amortization expense during the three months ended March 31, 2015 was largely driven by an increase in assets placed into service and contract amortization, with the substantial majority of the increase being attributed to Grand River Gathering and Polar and Divide.
Interest Expense. The increase in interest expense during the three months ended March 31, 2015, was primarily driven by our issuance of $300.0 million of 5.50% senior notes in July 2014.
For information on how our financial results are recognized, see the "Results of Operations" section of MD&A included in the 2014 Annual Report.
EX 99.2-6
EXHIBIT 99.2
Segment Overview of the Three Months Ended March 31, 2015 and 2014
Marcellus Shale. The Mountaineer Midstream gathering system provides our midstream services for the Marcellus Shale reportable segment. Marcellus Shale volume throughput averaged 547 MMcf/d for the three months ended March 31, 2015, compared with 286 MMcf/d in the prior-year period and reflects the continuation of active drilling by Mountaineer Midstream's anchor customer and the connection of new wells upstream of the Mountaineer Midstream system.
Information regarding our operations in the Marcellus Shale follows.
Marcellus Shale (1) | ||||||||||
Three months ended March 31, | Percentage Change | |||||||||
2015 | 2014 | 2015 v. 2014 | ||||||||
(Dollars in thousands) | ||||||||||
Revenues: | ||||||||||
Gathering services and related fees | $ | 7,840 | $ | 5,356 | 46 | % | ||||
Total revenues | 7,840 | 5,356 | 46 | % | ||||||
Costs and expenses: | ||||||||||
Operation and maintenance | 1,215 | 969 | 25 | % | ||||||
General and administrative | 90 | 504 | (82 | )% | ||||||
Depreciation and amortization | 2,168 | 1,801 | 20 | % | ||||||
Total costs and expenses | 3,473 | 3,274 | 6 | % | ||||||
Add: | ||||||||||
Depreciation and amortization | 2,168 | 1,801 | ||||||||
Segment adjusted EBITDA | $ | 6,535 | $ | 3,883 | 68 | % | ||||
Average throughput (MMcf/d) | 547 | 286 | 91 | % | ||||||
(1) Contract terms related to throughput rate per MCF are excluded for confidentiality purposes.
Segment adjusted EBITDA increased $2.7 million during the three months ended March 31, 2015 reflecting:
• | the impact of an increase in volume throughput which translated into higher gathering services and other fees revenue. |
• | the benefit of higher volume throughput was partially offset by a decline in compression services, which resulted from a shift in volume throughput mix to a larger percentage of previously compressed natural gas entering our gathering lines. As a result of this shift in volume throughput mix, the proportion of high-pressure gathering services increased, which, due to its lower rate relative to compression fees, negatively impacted gathering services and other fees as well as the average throughput rate per Mcf. |
• | minimum revenue commitment payments related to the recently completed Zinnia Loop project, received in the first quarter of 2015. |
• | an increase in operation and maintenance primarily as a result of system expansion and the associated increase in volume throughput. |
• | a decline in general and administrative expenses primarily as a result of our decision to discontinue allocating certain corporate expenses beginning in the first quarter of 2015. |
Depreciation and amortization increased during the three months ended March 31, 2015 largely as a result of assets placed into service during the third quarter of 2014, most notably the Zinnia Loop project.
Williston Basin – Gas. The Bison Midstream gathering system provides our midstream services for the Williston Basin – Gas reportable segment. Williston Basin – Gas volume throughput averaged 18 MMcf/d for the three months ended March 31, 2015, compared with 12 MMcf/d in the prior-year period. The increase in volume throughput in 2015 reflects additional pad site connections and compression capacity installed in the latter half of 2014, which improved system hydraulics. Volume throughput in the first quarter of 2014 also reflected the impact of severe winter weather in northwestern North Dakota and operational challenges caused by water hydrate issues.
EX 99.2-7
EXHIBIT 99.2
These issues were remediated during the second quarter of 2014. Bison Midstream's aggregate average throughput rate declined to $2.80 per Mcf during the three months ended March 31, 2015, compared with $4.59 per Mcf in the prior-year period, primarily as a result of a larger proportion of percent-of-proceeds contracts and the impact of declining commodity prices.
Information regarding our operations in the Williston Basin – Gas follows.
Williston Basin – Gas | ||||||||||
Three months ended March 31, | Percentage Change | |||||||||
2015 | 2014 | 2015 v. 2014 | ||||||||
(Dollars in thousands, except fee-rate data) | ||||||||||
Revenues: | ||||||||||
Gathering services and related fees | $ | 244 | $ | 209 | 17 | % | ||||
Natural gas, NGLs and condensate sales | 7,358 | 15,476 | (52 | )% | ||||||
Other revenues | 1,306 | 1,078 | 21 | % | ||||||
Total revenues | 8,908 | 16,763 | (47 | )% | ||||||
Costs and expenses: | ||||||||||
Cost of natural gas and NGLs | 3,079 | 10,789 | (71 | )% | ||||||
Operation and maintenance | 2,989 | 2,962 | 1 | % | ||||||
General and administrative | 167 | 1,028 | (84 | )% | ||||||
Depreciation and amortization | 4,698 | 4,250 | 11 | % | ||||||
Total costs and expenses | 10,933 | 19,029 | (43 | )% | ||||||
Add: | ||||||||||
Depreciation and amortization | 4,698 | 4,250 | ||||||||
Adjustments related to MVC shortfall payments | 2,660 | 2,692 | ||||||||
Segment adjusted EBITDA | $ | 5,333 | $ | 4,676 | 14 | % | ||||
Average throughput (MMcf/d) | 18 | 12 | 50 | % | ||||||
Average throughput rate per Mcf | $ | 2.80 | $ | 4.59 | (39 | )% | ||||
Segment adjusted EBITDA increased $0.7 million during the three months ended March 31, 2015 reflecting:
• | the previously mentioned decision to discontinue certain general and administrative expense allocations. |
• | the impact of declining commodity prices which negatively affected the margins we earn under percent-of-proceeds arrangements. |
• | a decrease in operation and maintenance expenses largely as a result of the first quarter 2014 water hydrate remediation effort. |
Depreciation and amortization increased during the three months ended March 31, 2015 largely as a result compression assets placed into service during the second half of 2014.
Williston Basin – Liquids. The Polar and Divide system provides our midstream services for the Williston Basin – Liquids reportable segment. Williston Basin – Liquids volume throughput averaged 59.9 Mbbl/d for the three months ended March 31, 2015, compared with 29.1 Mbbl/d in the prior-year period. The increase in volume throughput in 2015 reflects new pad site connections and ongoing drilling activity in Polar and Divide's service area. Polar Midstream's aggregate average throughput rate increased to $1.43 per Bbl during the three months ended March 31, 2015, compared with $1.06 per Bbl in the prior-year period, primarily as a result of contract amendments in 2014 which increased gathering rates in connection with our commitment to further expand the Polar and Divide system.
EX 99.2-8
EXHIBIT 99.2
Information regarding our operations in the Williston Basin – Liquids follows.
Williston Basin – Liquids | ||||||||||
Three months ended March 31, | Percentage Change | |||||||||
2015 | 2014 | 2015 v. 2014 | ||||||||
(Dollars in thousands, except fee-rate data) | ||||||||||
Revenues: | ||||||||||
Gathering services and related fees | $ | 7,726 | $ | 2,772 | * | |||||
Other revenues | 856 | 407 | 110 | % | ||||||
Total revenues | 8,582 | 3,179 | * | |||||||
Costs and expenses: | ||||||||||
Operation and maintenance | 2,317 | 1,723 | 34 | % | ||||||
General and administrative | 1,307 | 1,167 | 12 | % | ||||||
Depreciation and amortization | 1,612 | 737 | 119 | % | ||||||
Total costs and expenses | 5,236 | 3,627 | 44 | % | ||||||
Add: | ||||||||||
Depreciation and amortization | 1,612 | 737 | ||||||||
Unit-based compensation | 85 | 85 | ||||||||
Segment adjusted EBITDA | $ | 5,043 | $ | 374 | * | |||||
Average throughput (Mbbl/d) | 59.9 | 29.1 | 106 | % | ||||||
Average throughput rate per Bbl | $ | 1.43 | $ | 1.06 | 35 | % | ||||
__________
* Not considered meaningful
Segment adjusted EBITDA increased $4.7 million during the three months ended March 31, 2015 reflecting:
• | the impact of higher volume throughput on gathering services and related fees. |
• | higher gathering rates associated with contract amendments in 2014. |
• | an increase in operation and maintenance expenses largely as a result of system buildout. |
Other revenues and operation and maintenance also reflect the effect of an increase in connection fees, which, due to their pass-through nature, have no impact on segment adjusted EBITDA.
Depreciation and amortization increased during the three months ended March 31, 2015 largely as a result of gathering pipeline placed into service during 2014.
Barnett Shale. The DFW Midstream gathering system provides our midstream services for the Barnett Shale reportable segment. DFW Midstream volume throughput increased to 403 MMcf/d during the three months ended March 31, 2015, compared with 348 MMcf/d in the prior-year period. The increase in volume throughput primarily reflects customer production which recommenced from several pad sites that had been temporarily shut-in for drilling and completion activities beginning in the third quarter of 2013 and continuing until late 2014. In addition, DFW Midstream volume throughput benefited from the contribution of the Lonestar assets, which we acquired on September 30, 2014. These increases were partially offset by a lack of drilling activity by DFW Midstream's anchor customer. DFW Midstream's aggregate average throughput rate was relatively unchanged at $0.60 per Mcf during the three months ended March 31, 2015, compared with $0.59 per Mcf in the prior-year period.
EX 99.2-9
EXHIBIT 99.2
Information regarding our operations in the Barnett Shale follows.
Barnett Shale | ||||||||||
Three months ended March 31, | Percentage Change | |||||||||
2015 | 2014 | 2015 v. 2014 | ||||||||
(Dollars in thousands, except fee-rate data) | ||||||||||
Revenues: | ||||||||||
Gathering services and related fees | $ | 21,794 | $ | 19,177 | 14 | % | ||||
Natural gas, NGLs and condensate sales | 1,922 | 4,064 | (53 | )% | ||||||
Other revenues | 181 | (204 | ) | * | ||||||
Total revenues | 23,897 | 23,037 | 4 | % | ||||||
Costs and expenses: | ||||||||||
Operation and maintenance | 6,812 | 7,892 | (14 | )% | ||||||
General and administrative | 353 | 1,170 | (70 | )% | ||||||
Depreciation and amortization | 3,906 | 3,638 | 7 | % | ||||||
Total costs and expenses | 11,071 | 12,700 | (13 | )% | ||||||
Add: | ||||||||||
Depreciation and amortization | 4,157 | 3,864 | ||||||||
Adjustments related to MVC shortfall payments | (223 | ) | 833 | |||||||
Segment adjusted EBITDA | $ | 16,760 | $ | 15,034 | 11 | % | ||||
Average throughput (MMcf/d) | 403 | 348 | 16 | % | ||||||
Average throughput rate per Mcf | $ | 0.60 | $ | 0.59 | 2 | % | ||||
* Not considered meaningful
Segment adjusted EBITDA increased $1.7 million during the three months ended March 31, 2015 reflecting:
• | an increase in gathering services and other fees due to increased volumes. |
• | the impact of declining natural gas prices on the fuel retainage fee that is paid in-kind by certain of our customers to offset the costs we incur to operate DFW Midstream's electric-drive compression assets. |
• | a decline in operation and maintenance expense due to lower electricity expense and a decline in third-party natural gas treating expenses. We purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices. As a result, the decline in natural gas prices translated into lower electricity expenses. The natural gas price effect was partially offset by an increase in electricity usage due to higher volume throughput. |
• | a decline in third-party natural gas treating expenses, which we recognize in operation and maintenance. In February 2014, we commissioned a new 150 gallon per minute natural gas treating facility which allowed us to provide treating services to our customers rather than having to contract with a third-party service provider for treating services. |
• | a negative adjustment to MVC shortfall payments in the first quarter of 2015 for a customer that exceeded volume throughput expectations as a result of wells placed in service in December 2014. The 2015 adjustment was necessary to true-up the customer's balance due to its annual MVC period ending on April 10. |
• | the previously mentioned decision to discontinue certain general and administrative expense allocations. |
Depreciation and amortization increased during the three months ended March 31, 2015 largely as a result of placing the Lonestar assets into service in September 2014.
Piceance Basin. The Grand River Gathering system provides our midstream services for the Piceance Basin reportable segment. Red Rock Gathering became part of the Grand River Gathering system in connection with the Red Rock Drop Down in March 2014. Our results include activity for Red Rock Gathering since October 23, 2012,
EX 99.2-10
EXHIBIT 99.2
the date on which common control began. For additional information, see Notes 1 and 3 to the unaudited condensed consolidated financial statements.
Volume throughput for the Piceance Basin decreased to 615 MMcf/d during the three months ended March 31, 2015 from 665 MMcf/d during the prior-year period primarily as a result of Encana's temporary suspension of drilling activities, which began in the fourth quarter of 2013. This decline was partially offset by new pad site connections as well as the March 2014 start-up of a cryogenic processing plant. The aggregate average throughput rate increased to $0.42 per Mcf during the first quarter of 2015 from $0.38 per Mcf during the first quarter of 2014 largely as a result of the shift in volume throughput mix noted above. A shift in volume throughput mix has translated into higher average gathering rates per Mcf.
Certain of our gas gathering agreements for Grand River Gathering include MVCs that increase in both rate and volume commitment over the next few years and largely mitigate the financial impact associated with declining volumes from certain customers. As a result, lower volume throughput for the customers subject to these MVCs translated into larger MVC shortfall payments.
Information regarding our operations in the Piceance Basin follows.
Piceance Basin | ||||||||||
Three months ended March 31, | Percentage Change | |||||||||
2015 | 2014 | 2015 v. 2014 | ||||||||
(Dollars in thousands, except fee-rate data) | ||||||||||
Revenues: | ||||||||||
Gathering services and related fees | $ | 23,163 | $ | 22,389 | 3 | % | ||||
Natural gas, NGLs and condensate sales | 3,333 | 6,764 | (51 | )% | ||||||
Other revenue | 1,438 | 1,893 | (24 | )% | ||||||
Total revenues | 27,934 | 31,046 | (10 | )% | ||||||
Costs and expenses: | ||||||||||
Cost of natural gas and NGLs | 2,305 | 3,564 | (35 | )% | ||||||
Operation and maintenance | 7,724 | 8,286 | (7 | )% | ||||||
General and administrative | 572 | 2,103 | (73 | )% | ||||||
Depreciation and amortization | 11,205 | 9,811 | 14 | % | ||||||
Total costs and expenses | 21,806 | 23,764 | (8 | )% | ||||||
Add: | ||||||||||
Depreciation and amortization | 11,205 | 9,811 | ||||||||
Adjustments related to MVC shortfall payments | 9,903 | 8,488 | ||||||||
Segment adjusted EBITDA | $ | 27,236 | $ | 25,581 | 6 | % | ||||
Average throughput (MMcf/d) | 615 | 665 | (8 | )% | ||||||
Average throughput rate per Mcf | $ | 0.42 | $ | 0.38 | 11 | % | ||||
Segment adjusted EBITDA increased $1.7 million during the three months ended March 31, 2015 reflecting:
• | lower condensate sales due to a weak commodity price environment. |
• | the previously mentioned decision to discontinue certain general and administrative expense allocations. |
• | an increase in anticipated MVC shortfall payments due to increasing rate and volume commitment provisions in certain gas gathering agreements, as noted above. |
• | the impact of declining commodity prices which negatively impacted the margins that we earn from our percent-of-proceeds contracts. |
• | a decline in operation and maintenance due to lower utilities and compression expenses and property taxes, partially offset by an increase in salaries and benefits. |
EX 99.2-11
EXHIBIT 99.2
Depreciation and amortization increased $1.4 million during the three months ended March 31, 2015 largely as a result of an increase in contract amortization for Grand River Gathering's anchor customer and the March 2014 commissioning of the cryogenic processing plant.
Corporate. Corporate represents those revenues and expenses that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, transaction costs and interest expense. Items to note follow.
Corporate | ||||||||||
Three months ended March 31, | Percentage Change | |||||||||
2015 | 2014 | 2015 v. 2014 | ||||||||
(In thousands) | ||||||||||
Costs and expenses: | ||||||||||
General and administrative | $ | 7,169 | $ | 3,081 | 133 | % | ||||
Transaction costs | — | 537 | (100 | )% | ||||||
Depreciation and amortization | 166 | 142 | 17 | % | ||||||
Interest expense | 12,118 | 7,144 | 70 | % | ||||||
General and Administrative. The increase in general and administrative expense during the three months ended March 31, 2015, largely reflects the impact of our decision to discontinue allocating certain expenses, primarily salaries, benefits, incentive compensation and rent expense, to our operating segments.
Transaction Costs. Transaction costs recognized during the three months ended March 31, 2014 primarily relate to financial and legal advisory costs associated with the Red Rock Drop Down.
Interest Expense. The increase in interest expense during the three months ended March 31, 2015, was primarily driven by our issuance of $300.0 million of 5.50% senior notes in July 2014.
Non-GAAP Financial Measures
EBITDA, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We define EBITDA as net income, plus interest expense, income tax expense, and depreciation and amortization, less interest income and income tax benefit. We define adjusted EBITDA as EBITDA plus adjustments related to MVC shortfall payments, impairments and other noncash expenses or losses, less other noncash income or gains. We define distributable cash flow as adjusted EBITDA plus cash interest received, less cash interest paid, senior notes interest, cash taxes paid and maintenance capital expenditures. We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations.
Net income and net cash provided by operating activities are the GAAP financial measures most directly comparable to EBITDA, adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. For additional information on the limitations of our non-GAAP financial measures and how we compensate for those limitations, see the "Non-GAAP Financial Measures" section of MD&A included in the 2014 Annual Report.
Non-GAAP reconciliations items to note. The following items should be noted when reviewing our non-GAAP reconciliations:
• | Interest expense presented in the net income-basis non-GAAP reconciliation includes amortization of deferred loan costs while interest expense presented in the cash flow-basis non-GAAP reconciliation is adjusted to exclude amortization of deferred loan costs. See the unaudited condensed consolidated statements of cash flows for additional information. |
• | Depreciation and amortization includes the favorable and unfavorable gas gathering contract amortization expense reported in other revenues. |
• | Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected minimum volume commitment shortfall payments in each quarter prior to the quarter in which we actually receive the shortfall payment. |
EX 99.2-12
EXHIBIT 99.2
• | Senior notes interest represents the net of interest expense accrued and paid during the period. See "Liquidity and Capital Resources—Long-Term Debt" and Note 7 to the consolidated financial statements included in the 2014 Annual Report. |
• | Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity. |
• | As a result of accounting for our drop down transactions similar to a pooling of interests, EBITDA, adjusted EBITDA, and distributable cash flow reflect the historical operations, financial position and cash flows of Polar Midstream, Epping and Red Rock Gathering for the periods beginning with the date that common control began and ending on the date that the respective drop down closed. See Notes 1 and 15 to the unaudited condensed consolidated financial statements and Note 15 to the consolidated financial statements included in the 2014 Annual Report. |
• | EBITDA, adjusted EBITDA, distributable cash flow and net cash provided by operating activities include transaction costs. These unusual expenses are settled in cash. For additional information, see "Results of Operations—Corporate" herein. |
Net Income-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of net income to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.
Three months ended March 31, | |||||||
2015 | 2014 | ||||||
(In thousands) | |||||||
Reconciliation of net income to EBITDA, adjusted EBITDA and distributable cash flow: | |||||||
Net income | $ | 5,013 | $ | 5,925 | |||
Add: | |||||||
Interest expense | 12,118 | 7,144 | |||||
Income tax expense | 177 | 159 | |||||
Depreciation and amortization | 24,006 | 20,605 | |||||
Less: | |||||||
Interest income | 1 | 1 | |||||
EBITDA | $ | 41,313 | $ | 33,832 | |||
Add: | |||||||
Adjustments related to MVC shortfall payments | 12,340 | 12,013 | |||||
Unit-based compensation | 1,397 | 1,148 | |||||
Adjusted EBITDA | $ | 55,050 | $ | 46,993 | |||
Add: | |||||||
Cash interest received | 1 | 1 | |||||
Less: | |||||||
Cash interest paid | 22,812 | 14,308 | |||||
Senior notes interest | (11,171 | ) | (6,500 | ) | |||
Maintenance capital expenditures | 2,484 | 5,584 | |||||
Distributable cash flow | $ | 40,926 | $ | 33,602 | |||
EX 99.2-13
EXHIBIT 99.2
Cash Flow-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.
Three months ended March 31, | |||||||
2015 | 2014 | ||||||
(In thousands) | |||||||
Reconciliation of net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow: | |||||||
Net cash provided by operating activities | $ | 54,786 | $ | 48,243 | |||
Add: | |||||||
Interest expense | 11,327 | 6,540 | |||||
Income tax expense | 177 | 159 | |||||
Changes in operating assets and liabilities | (23,579 | ) | (19,961 | ) | |||
Less: | |||||||
Unit-based compensation | 1,397 | 1,148 | |||||
Interest income | 1 | 1 | |||||
EBITDA | $ | 41,313 | $ | 33,832 | |||
Add: | |||||||
Adjustments related to MVC shortfall payments | 12,340 | 12,013 | |||||
Unit-based compensation | 1,397 | 1,148 | |||||
Adjusted EBITDA | $ | 55,050 | $ | 46,993 | |||
Add: | |||||||
Cash interest received | 1 | 1 | |||||
Less: | |||||||
Cash interest paid | 22,812 | 14,308 | |||||
Senior notes interest | (11,171 | ) | (6,500 | ) | |||
Maintenance capital expenditures | 2,484 | 5,584 | |||||
Distributable cash flow | $ | 40,926 | $ | 33,602 | |||
Liquidity and Capital Resources
Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt securities.
Capital Markets Activity
We had no capital markets activity during the three months ended March 31, 2015.
Long-Term Debt
Revolving Credit Facility. We have a $700.0 million senior secured revolving credit facility. The revolving credit facility is secured by the membership interests of Summit Holdings and those of its subsidiaries. Substantially all of the assets of Summit Holdings and its subsidiaries are pledged as collateral under the revolving credit facility. The revolving credit facility, and Summit Holdings' obligations, are guaranteed by SMLP and each of its subsidiaries. As of March 31, 2015, the outstanding balance of the revolving credit facility was $196.0 million and the unused portion totaled $504.0 million. As of March 31, 2015, we were in compliance with the covenants in the revolving credit facility. There were no defaults or events of default during the three months ended March 31, 2015.
Senior Notes. In July 2014, Summit Holdings and Summit Midstream Finance Corp. co-issued $300.0 million of 5.50% senior unsecured notes maturing August 15, 2022. In June 2013, they co-issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021. There were no defaults or events of default during the three months ended March 31, 2015 on either series of senior notes.
EX 99.2-14
EXHIBIT 99.2
For additional information, see Note 8 to the unaudited condensed consolidated financial statements.
Cash Flows
The components of the change in cash and cash equivalents were as follows:
Three months ended March 31, | |||||||
2015 | 2014 | ||||||
(In thousands) | |||||||
Net cash provided by operating activities | $ | 54,786 | $ | 48,243 | |||
Net cash used in investing activities | (28,129 | ) | (358,580 | ) | |||
Net cash (used in) provided by financing activities | (40,007 | ) | 300,384 | ||||
Change in cash and cash equivalents | $ | (13,350 | ) | $ | (9,953 | ) | |
Operating activities. Cash flows from operating activities increased by $6.5 million for the three months ended March 31, 2015 primarily due to cash received as a result of MVCs. These cash receipts were largely offset by an increase in interest due to the 5.5% senior notes and other operating activities.
Investing activities. Cash flows used in investing activities for the three months ended March 31, 2015 were related primarily to (i) the ongoing expansion of the Polar and Divide system, (ii) expansion of compression capacity on the Bison Midstream system, (iii) pipeline construction projects to connect new receipt points on the Grand River and Bison Midstream systems and (iv) the settlement of the working capital adjustment associated with the Red Rock Drop Down.
Cash flows used in investing activities for the three months ended March 31, 2014 primarily reflect the Partnership's acquisition of Red Rock Gathering from a subsidiary of Summit Investments. Additional expenditures for the three months ended March 31, 2014 primarily reflect (i) construction of a processing plant for Grand River Gathering, (ii) ongoing expansion of the Polar and Divide system, (iii) projects to expand compression capacity on the Bison Midstream system and (iv) adding pipeline on the Mountaineer Midstream system.
Financing activities. Details of cash flows provided by financing activities were as follows:
Three months ended March 31, | |||||||
2015 | 2014 | ||||||
(In thousands) | |||||||
Cash flows from financing activities: | |||||||
Distributions to unitholders | $ | (35,093 | ) | $ | (26,366 | ) | |
Borrowings under revolving credit facility | 14,000 | 125,000 | |||||
Repayments under revolving credit facility | (26,000 | ) | (20,000 | ) | |||
Deferred loan costs | (15 | ) | (65 | ) | |||
Tax withholdings on vested SMLP LTIP awards | (910 | ) | (656 | ) | |||
Proceeds from issuance of common units, net | — | 198,095 | |||||
Contribution from general partner | — | 4,235 | |||||
Cash advance from Summit Investments to contributed subsidiaries, net | 5,899 | 14,278 | |||||
Expenses paid by Summit Investments on behalf of contributed subsidiaries | 2,112 | 5,863 | |||||
Net cash (used in) provided by financing activities | $ | (40,007 | ) | $ | 300,384 | ||
Net cash used in financing activities for the three months ended March 31, 2015 was primarily composed of the following:
• | Distributions declared in respect of the fourth quarter of 2014 (paid in the first quarter of 2015); and |
• | Net repayments under our revolving credit facility. |
EX 99.2-15
EXHIBIT 99.2
Net cash provided by financing activities for the three months ended March 31, 2014 was primarily composed of the following:
• | Net proceeds from an offering of common units in March 2014, which were used to partially fund the Red Rock Drop Down; |
• | Net borrowings of $105.0 million under our revolving credit facility, including $100.0 million to partially fund the Red Rock Drop Down; and |
• | Distributions declared in respect of the fourth quarter of 2013 (paid in the first quarter of 2014). |
Capital Requirements
Our business is capital-intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement requires that we categorize our capital expenditures as either:
• | maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or |
• | expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. |
For the three months ended March 31, 2015, SMLP recorded total capital expenditures of $25.2 million, which included $2.5 million of maintenance capital expenditures.
We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under the revolving credit facility and the issuance of debt and equity securities.
We believe that our existing $700.0 million revolving credit facility, which had approximately $504.0 million of available capacity at March 31, 2015, together with our access to the debt and equity capital markets, will be adequate to finance our acquisition strategy for the foreseeable future without adversely impacting our liquidity or our ability to make quarterly cash distributions to our unitholders.
Distributions
Based on the terms of our partnership agreement, we expect to distribute to unitholders most of the cash generated by our operations. For additional information, see Note 9 to the unaudited condensed consolidated financial statements.
Credit Risk and Customer Concentration
We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. For additional information, see Note 12 to the unaudited condensed consolidated financial statements.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of or during the three months ended March 31, 2015.
Critical Accounting Estimates
We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. Our significant accounting policies are described in Note 2 to the unaudited condensed consolidated financial statements.
The estimates that we deem to be most critical to an understanding of our financial position and results of operations are those related to determination of fair value and recognition of deferred revenue. The preparation and evaluation of these critical accounting estimates involve the use of various assumptions developed from
EX 99.2-16
EXHIBIT 99.2
management's analyses and judgments. Subsequent experience or use of other methods, estimates or assumptions could produce significantly different results.
There have been no changes in the accounting methodology for items that we have identified as critical accounting estimates during the three months ended March 31, 2015.
Goodwill. As of December 31, 2014, our preliminary estimates of the fair values of the identified assets and liabilities calculated in the step two testing of the Bison Midstream reporting unit indicated that all of the associated goodwill had been impaired. In the first quarter of 2015, we finalized our calculations of the fair values of the identified assets and liabilities, confirming the preliminary goodwill impairment of $54.2 million. For additional information, see Note 5 to the consolidated financial statements included in the 2014 Annual Report.
For additional information regarding critical accounting estimates generally, see the "Critical Accounting Estimates" section of MD&A included in the 2014 Annual Report.
EX 99.2-17