Exhibit 99.3

 

SELECTED COMBINED HISTORICAL FINANCIAL DATA OF

ENLINK MIDSTREAM HOLDINGS, LP PREDECESSOR

 

The following table presents the selected historical financial and operating data of EnLink Midstream Holdings, LP Predecessor (the “Predecessor”), whose assets comprise the Midstream Business, for the periods indicated. The selected combined historical financial data of the Predecessor are derived from the historical combined financial statements of the Predecessor and should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” below and its audited combined financial statements for the year ended December 31, 2013 attached as Exhibit 99.4 to this Current Report on Form 8-K. The following information is only a summary and is not necessarily indicative of the results or future operations of the Predecessor.

 

		Year Ended December 31,
		2013			2012			2011			2010			2009
														(unaudited)
		(in millions, except per unit and operating data)
Key Performance Measure
Operating Margin (1)		$	446.3		$	365.3		$	453.8		$	427.6		$	366.8
Operating Data
Throughput (thousands of MMBtu/d)		2,708.4			2,720.6			2,637.4			2,470.0			2,294.2
NGL production (MBbls/d)		88.6			71.0			69.7			62.1			59.3
Statement of Income Data
Operating revenues		$	2,390.7		$	2,000.8		$	2,623.4		$	2,016.0		$	1,609.1
Operating expenses		(2,227.1		)	(1,899.2		)	(2,311.8		)	(1,766.9		)	(1,436.7		)
Operating income		163.6			101.6			311.6			249.1			172.4
Income from equity investment		14.8			2.0			9.3			5.1			5.0
Income tax expense		(64.2		)	(37.3		)	(115.5		)	(91.5		)	(63.8		)
Net income from continuing operations		114.2			66.3			205.4			162.7			113.6
Net income from discontinued operations		1.3			9.5			10.7			16.0			11.6
Net income		$	115.5		$	75.8		$	216.1		$	178.7		$	125.2
Balance Sheet Data
Net property, plant and equipment		$	1,840.4		$	1,843.2		$	1,687.0		$	1,574.6		$	1,499.2
Total assets		$	2,309.8		$	2,535.2		$	2,446.3		$	2,336.0		$	2,276.6
Total long-term liabilities		$	481.4		$	449.8		$	461.0		$	418.0		$	318.1
Total equity		$	1,783.7		$	2,002.0		$	1,901.3		$	1,849.0		$	1,869.7
Cash Flow Data
Net cash flows provided by (used in):
Operating activities		$	360.5		$	254.4		$	401.2		$	391.5		$	—
Investing activities		$	(242.9	)	$	(368.5	)	$	(268.6	)	$	(220.4	)	$	—
Financing activities		$	(117.6	)	$	114.1		$	(132.6	)	$	(171.1	)	$	—

 

 

(1)  Operating margin is a non-GAAP financial measure. See below for additional information and a reconciliation of operating margin to operating income, which is its most directly comparable GAAP financial measure.

 

Predecessor Non-GAAP Financial Measure

 

The selected combined historical financial data of the Predecessor includes operating margin, a non-GAAP financial measure.

 

The Predecessor’s operating margin is defined as operating revenues less product purchases and operations and maintenance expenses. The Predecessor uses operating margin as a performance measure of the core profitability of its operations. As an indicator of the Predecessor’s operating performance, operating margin should not be considered an alternative to, or more meaningful than, operating income or net income as determined in accordance with GAAP. The Predecessor’s operating margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

 

The following table provides a reconciliation of the Predecessor’s operating margin to operating income, which is the most directly comparable GAAP financial measure:

 

		Years Ended December 31,
		2013			2012			2011			2010			2009
		(in millions)
Predecessor’s operating margin		$	446.3		$	365.3		$	453.8		$	427.6		$	366.8
Add (deduct):
Depreciation and amortization		(199.0		)	(159.8		)	(144.8		)	(124.9		)	(136.6		)
General and administrative		(47.0		)	(43.6		)	(40.1		)	(39.4		)	(44.8		)
Non-income taxes		(18.0		)	(13.2		)	(15.3		)	(13.8		)	(12.5		)
Asset impairments		(18.2		)	(50.1		)	—			—			—
Other, net		(0.5		)	3.0			58.0			(0.4		)	(0.5		)
Operating income		$	163.6		$	101.6		$	311.6		$	249.1		$	172.4

 

Non-GAAP Financial Measure

 

Predecessor includes in this exhibit the non-GAAP financial measure ‘‘Adjusted EBITDA.’’ The Predecessor uses Adjusted EBITDA as a performance and liquidity measure to assess the ability of its assets to generate cash sufficient to pay interest costs and support indebtedness. The Partnership expects that Adjusted EBITDA will be a financial measure reported to its lenders and used as a gauge for compliance with some of its anticipated financial covenants under its credit facility. The Partnership defines Adjusted EBITDA as income from continuing operations before interest expense, income taxes, depreciation and amortization expense, impairments, stock-based compensation, income from equity investment, non-controlling interests and other income related items plus distributions from equity investment. The Partnership uses Adjusted EBITDA to assess:

 

 

·                  the financial performance of its assets, without regard to financing methods, capital structure or historical cost basis;

·                  its operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

·                  the viability of acquisitions and capital expenditure projects.

 

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income attributable to Midstream Holdings. The non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to the GAAP measures of net income attributable to Midstream Holdings. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool because it includes some, but not all, items that are included in net income are attributable to Midstream Holdings. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of results as reported under GAAP. Midstream Holdings and EnLink’s definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

 

The following table presents a reconciliation of the Predecessor’s net income to Adjusted EBITDA:

 

		Years Ended December 31,
		2013			2012			2011			2010			2009
		(In millions)
Net income from continuing operations attributable to Predecessor		$	114.2		$	66.3		$	205.4		$	162.7		$	113.6
Depreciation and amortization		199.0			159.8			144.8			124.9			136.6
Impairment		18.2			50.1			—			—			—
Income from equity investment		(14.8		)	(2.0		)	(9.3		)	(5.1		)	(5.0		)
Distributions from equity investment		12.0			2.3			8.3			8.7			5.0
Stock-based compensation		12.8			12.8			12.6			12.7			12.3
Taxes		64.2			37.3			115.5			91.5			63.8
Other (a)		0.5			(3.0		)	(58.0		)	0.4			0.5
Adjusted EBITDA		$	406.1		$	323.6		$	419.3		$	395.8		$	326.8

 

(a)         Other income is not included in adjusted EBITDA.

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OF ENLINK MIDSTREAM PARTNERS, LP

 

The historical financial statements included in this filing reflect the assets, liabilities and operations of the historical predecessor of EnLink Midstream Partners, LP (formerly known as Crosstex Energy, L.P.) (the “Partnership”) following the Partnership’s acquisition (the “Acquisition”) of 50% of the outstanding limited partner interests in EnLink Midstream Holdings, LP (formerly known as Devon Midstream Holdings, L.P.) (“Midstream Holdings”) and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC (formerly known as Devon Midstream Holdings GP, LLC), the general partner of Midstream Holdings (“Midstream Holdings GP” and, together with Midstream Holdings and their subsidiaries, the “Midstream Group Entities”).

 

Under the acquisition method of accounting, Midstream Holdings is considered the historical predecessor of the Partnership’s business because Devon Energy Corporation (“Devon”) obtained control of the Partnership through its control of EnLink Midstream, LLC (“ENLC”) and ENLC’s indirect acquisition of EnLink Midstream GP, LLC (formerly known as Crosstex Energy GP, LLC) (the “General Partner”) concurrently with the consummation of the Acquisition (collectively, the “business combination”).  Accordingly, the following discussion analyzes the results of operations and financial condition of EnLink Midstream Holdings, LP Predecessor (the “Predecessor”), the predecessor to Midstream Holdings. The Predecessor is comprised of all of the U.S. midstream assets and operations of Devon prior to the business combination, including its 38.75% economic interest in Gulf Coast Fractionators.  However, in connection with the business combination, only the Predecessor’s systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales in Texas and Oklahoma, as well as the economic burdens and benefits of the 38.75% economic interest in Gulf Coast Fractionators, was contributed to Midstream Holdings, effective as of December 31, 2013. These contributed assets represent 95.2% of the Predecessor’s operating income for the year ended December 31, 2013.

 

The following discussion analyzes the results of operations and financial condition of the Predecessor, including the less significant assets that were not contributed to Midstream Holdings in connection with the business combination. You should read this discussion in conjunction with the historical and pro forma financial statements and accompanying notes included in this filing. All references in this section to Midstream Holdings, as well as the terms “our,” “we,” “us” and “its,” refer to the Predecessor when used in historical context. All references in this section to the Partnership, as well as the terms “our,” “we,” “us” and “its,” refer to the EnLink Midstream Partners, LP, together with its consolidated subsidiaries, when referring to current or future events.

 

This management’s discussion and analysis of financial condition and results of operations contains forward-looking statements that involve risks, uncertainties and assumptions. See “Disclosure Regarding Forward-Looking Statements” for a discussion of the risks, uncertainties and assumptions associated with those statements. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including but not limited to those in “Risk Factors” and included in other portions of this filing.

 

Overview

 

We are a Delaware limited partnership formed on July 12, 2002. We primarily focus on providing midstream energy services, including gathering, transmission, processing, fractionation and marketing, to producers of natural gas, NGLs, crude oil and condensate. We also provide crude oil, condensate and brine services to producers. Our midstream energy asset network includes approximately 7,300 miles of pipelines, 12 natural gas processing plants, six fractionators, 3.1 million barrels of NGL cavern storage, rail terminals, barge terminals, truck terminals and a fleet of approximately 100 trucks.

 

Effective as of March 7, 2014, our wholly-owned subsidiary acquired 50% of the outstanding limited partner interests in Midstream Holdings and all of the outstanding equity interests in Midstream Holdings GP in exchange for the issuance by the Partnership of 120,542,441 units representing a new class of limited partnership interests in the Partnership.  At the same time, Crosstex Energy, Inc. (to be renamed EnLink Midstream, Inc.), the entity that directly owns our General Partner, became a wholly-owned subsidiary of ENLC.  Another wholly-owned subsidiary of ENLC owns the remaining 50% of the outstanding limited partner interests in Midstream Holdings.

 

Midstream Holdings owns midstream assets consisting of natural gas gathering and transportation systems, natural gas processing facilities and NGL fractionation facilities located in Texas and Oklahoma. Midstream Holdings’ primary assets consist of three processing facilities with 1.3 Bcf/d of natural gas processing capacity, approximately 3,685 miles of pipelines with aggregate capacity of 2.9 Bcf/d and fractionation facilities with up to 160 MBbls/d of aggregate NGL fractionation capacity. These assets include the following systems and facilities.

 

· Barnett assets —Midstream Holdings owns the following midstream assets in the Barnett Shale:

 

 

·Bridgeport processing facility —This natural gas processing facility is one of the largest processing plants in the U.S. with 790 MMcf/d of processing capacity, 63 MBbls/d of NGL production capacity and 15 MBbls/d of NGL fractionation capacity.

 

·Bridgeport rich gathering system —This rich natural gas gathering system consists of approximately 2,442 miles of low- and intermediate-pressure pipeline segments with approximately 145,000 horsepower of compression.

 

·Bridgeport lean gathering system —This lean natural gas gathering system consists of approximately 300 miles of low-, intermediate- and high-pressure pipeline segments with approximately 59,000 horsepower of compression.

 

·Acacia transmission system —This transmission system consists of approximately 120 miles of pipeline, associated storage and approximately 17,000 horsepower of compression and interconnects the tailgate of the Bridgeport processing facility and the Bridgeport lean gathering system to intrastate pipelines as well as two local power plants.

 

·East Johnson County gathering system —This natural gas gathering system consists of approximately 270 miles of low-, intermediate- and high-pressure pipeline segments with approximately 41,000 horsepower of compression.

 

· Cana system —This natural gas gathering and processing system is located in the Cana-Woodford Shale in West Central Oklahoma and consists of a 350 MMcf/d processing facility, 30 MBbls/d of NGL production capacity and approximately 413 miles of associated low-, intermediate- and high-pressure pipeline segments with approximately 92,500 horsepower of compression.

 

·Northridge system —This natural gas gathering and processing system is located in the Arkoma-Woodford Shale in Southeastern Oklahoma and consists of a 200 MMcf/d processing facility, 17 MBbls/d of NGL production capacity and approximately 140 miles of associated low-, intermediate- and high-pressure pipeline segments with approximately 18,000 horsepower of compression.

 

·Gulf Coast Fractionators —Midstream Holdings holds a contractual right to the economic burdens and benefits of a 38.75% interest in Gulf Coast Fractionators held by Devon. Gulf Coast Fractionators owns an NGL fractionator located on the Texas Gulf Coast at the Mont Belvieu hub. This facility has a capacity of approximately 145 MBbls/d.

 

Midstream Holdings’ Operations

 

Midstream Holdings’ results are driven primarily by the volumes of natural gas it gathers, processes and transports through its systems. This volume throughput is substantially dependent on Devon’s success in the regions where Midstream Holdings operates. Devon is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon is the largest natural gas producer in the Barnett and Cana-Woodford Shales, the largest NGL producer in the Barnett Shale and one of the largest NGL producers in the Cana-Woodford Shale.

 

In Midstream Holdings’ gathering operations, it contracts with producers to gather natural gas from individual wells located near its gathering systems. Midstream Holdings connects wells to gathering lines through which natural gas is compressed and may be delivered to a processing plant or downstream pipeline, and ultimately to end-users.

 

The Predecessor historically provided services to Devon pursuant to fixed-fee and percent-of-proceeds contracts and historically took title to the natural gas it gathered and processed.  The Predecessor’s percent-of-proceeds arrangements were based on the sales value of extracted NGLs and residue natural gas that resulted from natural gas processing.

 

In connection with the consummation of the Merger, Midstream Holdings has entered into new contracts with Devon pursuant to which it provides services under fixed-fee arrangements based on the volume and thermal content of the natural gas gathered, processed and transported and does not take title to the natural gas gathered, processed and transported. Under these arrangements, Midstream Holdings provides gathering and processing services to Devon, and Devon has dedicated to Midstream Holdings natural gas production for 10 years from 795,000 net acres in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. Midstream Holdings expects all of these dedications to result in associated deliveries to its Bridgeport,

 

 

Cana, East Johnson County and Northridge systems. Devon has provided five-year minimum natural gas volume commitments to Midstream Holdings of 850 MMcf/d to the Bridgeport gathering systems, 650 MMcf/d to the Bridgeport processing facility, 125 MMcf/d to the East Johnson County gathering system, 330 MMcf/d to the Cana system and 40 MMcf/d to the Northridge system.

 

Midstream Holdings believes these contracts provide it with a relatively steady revenue stream that is not subject to direct commodity price risk during the term of the five-year minimum volume commitments. After the five-year minimum volume commitments, Midstream Holdings will nevertheless continue to have indirect exposure to commodity price risk in that persistently low commodity prices may cause Devon to delay drilling or shut in production, which would reduce the throughput on Midstream Holdings’ assets.

 

How Midstream Holdings Evaluates its Operations

 

Midstream Holdings uses a variety of financial and operational metrics to evaluate its performance. These metrics help Midstream Holdings identify factors and trends that impact Midstream Holdings’ operating results, profitability and financial condition. The key metrics Midstream Holdings uses to evaluate its business are provided below.

 

Operating Margin

 

Midstream Holdings uses operating margin as a performance measure of the core profitability of its operations. Midstream Holdings defines operating margin as total operating revenues, which consist of revenues generated from the sale of natural gas and NGLs plus service fee revenues, less the cost of product purchases, consisting primarily of producer payments and other natural gas purchases, and operations and maintenance expenses. Midstream Holdings uses operating margin to assess:

 

· the financial performance of Midstream Holdings’ assets, without regard to financing methods, capital structure or historical cost basis;

 

· Midstream Holdings’ operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

 

· the viability of acquisitions and capital expenditure projects.

 

Natural Gas Throughput

 

Midstream Holdings must continually obtain additional supplies of natural gas to maintain or increase throughput on its systems. Midstream Holdings’ ability to maintain existing supplies of natural gas and obtain additional supplies is primarily impacted by its acreage dedication and the level of successful drilling activity by Devon and, to a lesser extent, the acreage dedications with and successful drilling by other producers.

 

Items Affecting Comparability of Midstream Holdings’ Financial Results

 

The historical financial results of the Predecessor discussed below may not be comparable to Midstream Holdings’ future financial results for the following reasons:

 

·The Predecessor’s historical assets comprised all of Devon’s U.S. midstream assets and operations. However, only its assets serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as the 38.75% economic interest in Gulf Coast Fractionators, were contributed to Midstream Holdings in connection with the consummation of the Merger. These assets generated approximately 96% of the Predecessor’s net income from continuing operations for year ended December 31, 2013.

 

·Midstream Holdings has entered into new agreements with Devon pursuant to which Midstream Holdings provides services under fixed-fee arrangements and no longer takes title to the natural gas gathered and processed or the NGLs it fractionates.

 

·The Predecessor’s historical combined financial statements include U.S. federal and state income tax expense. Due to Midstream Holdings’ status as a partnership, the 50% interest in Midstream Holdings that is owned directly by the Partnership will not be subject to U.S. federal income tax and certain state income taxes in the future.

 

 

·All historical affiliated transactions related to Midstream Holdings’ continuing operations were net settled within its combined financial statements because these transactions related to Devon and were funded by Devon’s working capital. In the future, all of Midstream Holdings’ transactions will be funded by its working capital. This will impact the comparability of its cash flow statements, working capital analysis and liquidity discussion.

 

General Trends and Outlook

 

Natural Gas and NGL Supply and Demand

 

Midstream Holdings’ gathering and processing operations are generally dependent upon natural gas production from Devon’s upstream activity in its areas of operation. The significant decline in natural gas prices as a result of significant new supplies of domestic natural gas production has caused a related decrease in dry natural gas drilling by many producers in the United States. Depressed oil and natural gas prices could affect production rates over time and levels of investment by Devon and third parties in exploration for and development of new oil and natural gas reserves. In addition, there is a natural decline in production from existing wells that are connected to Midstream Holdings’ gathering systems. Midstream Holdings believes Devon’s five-year minimum volume commitments substantially reduce Midstream Holdings’ volumetric risk over that period of time. After the expiration of these five-year minimum volume commitments, a material decline in the volume of natural gas that Midstream Holdings gathers and transports on its systems would result in a material decline in its total operating revenues and cash flows. Although Midstream Holdings expects that Devon will continue to devote substantial resources to the development of the Barnett and Cana-Woodford Shales, it has no control over this activity and Devon has the ability to reduce or curtail such development at its discretion.

 

Rising Operating Costs and Inflation

 

The current level of exploration, development and production activities across the United States has resulted in increased competition for personnel and equipment. This competition has caused, and Midstream Holdings believes it will continue to cause, increases in the prices it pays for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect on the operating costs Midstream Holdings incurs. Midstream Holdings will attempt to recover increased costs from its customers, but there may be a delay in doing so or it may be unable to recover all these costs. To the extent Midstream Holdings is unable to procure necessary supplies or recover higher costs, its operating results will be negatively impacted.

 

Regulatory Compliance

 

The regulation of natural gas gathering and transportation activities by FERC and other federal and state regulatory agencies, including the DOT, has a significant impact on Midstream Holdings’ business. For example, PHMSA has established pipeline integrity management programs that require more frequent inspections of pipeline facilities and other preventative measures, which may increase Midstream Holdings’ compliance costs and increase the time it takes to obtain required permits. Additionally, increased regulation of oil and natural gas producers, including regulation associated with hydraulic fracturing, could reduce regional supply of oil and natural gas and therefore throughput on Midstream Holdings’ gathering systems.

 

Results of Predecessor’s Operations

 

The following schedule presents the Predecessor’s historical combined key operating and financial metrics.

 

		Year Ended December 31,
		2013			2012			2011
		($ in millions, except prices)
Operating revenues		$	2,390.7		$	2,000.8		$	2,623.4
Product purchases		(1,773.7		)	(1,464.5		)	(2,014.1		)
Operations and maintenance expenses		(170.7		)	(171.0		)	(155.5		)
Operating margin		446.3			365.3			453.8
Other operating expenses, net		(282.7		)	(263.7		)	(142.2		)

 

 

		Year Ended December 31,
		2013			2012			2011
Income from equity investment		14.8			2.0			9.3
Income tax expense		(64.2		)	(37.3		)	(115.5		)
Net income from continuing operations		114.2			66.3			205.4
Net income from discontinued operations		1.3			9.5			10.7
Net income attributable to Devon		$	115.5		$	75.8		$	216.1
Throughput (thousands of MMBtu/d):
Bridgeport rich gathering system		861.1			818.4			811.6
Bridgeport lean gathering system		261.8			298.0			296.0
Acacia transmission system		741.8			732.7			700.1
East Johnson County gathering system		236.8			277.8			258.0
Barnett assets		2,101.5			2,126.9			2,065.7
Cana gathering system		320.7			265.7			175.7
Northridge gathering system		69.2			85.0			109.5
Other systems		217.0			243.0			286.5
Total		2,708.4			2,720.6			2,637.4
NGL production (MBbls/d):
Bridgeport processing facility		58.9			49.4			52.8
Cana processing facility		18.8			12.1			3.9
Northridge processing facility		8.2			6.8			10.5
Other systems		2.7			2.7			2.5
Total		88.6			71.0			69.7
Residue natural gas production (thousands of MMBtu/d):
Bridgeport processing facility		623.1			613.1			599.5
Cana processing facility		242.1			209.7			151.5
Northridge processing facility		52.2			65.5			85.3
Other systems		7.4			7.4			2.6
Total		924.8			895.7			838.9
Realized prices:
NGLs ($/Bbl)		$	30.05		$	35.38		$	49.16
Residue natural gas ($/MMBtu)		$	3.18		$	2.38		$	3.58

 

Since 2011, operating margin has consistently improved as a result of production growth. The largest contributors to rising production have been Midstream Holdings’ Cana, Bridgeport rich, and Acacia systems, with daily throughput growth of 83%, 6%, and 6%, respectively, from 2011 to 2013. This growth is the result of Devon and other producers developing liquids-rich natural gas production in the Cana-Woodford and Barnett Shales. However, overall growth has been limited by throughput declines for the Predecessor’s other systems, which are the result of natural gas price decreases. As natural gas prices have dropped relative to oil and NGL prices in recent years, many producers, including Devon, have focused on growing their oil and liquids-rich natural gas production rather than dry natural gas. Consequently, Midstream Holdings’ systems serving liquids-rich natural gas regions in the Cana-Woodford and Barnett Shales have higher throughput, while Midstream Holdings’ systems serving dry natural gas regions have experienced throughput declines.

 

Prices have also impacted operating margin. Since 2011, NGL prices have declined significantly, which has negatively impacted operating margin. Natural gas prices have been volatile, increasing in 2013 after a significant decline in 2012.

 

 

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

 

Operating Margin

 

Operating margin increased $81.0 million, or 22%, from the year ended December 31, 2012 to the year ended December 31, 2013, as summarized in the following schedule:

 

		(in millions)
Operating margin, 2012		$	365.3
Change due to volumes		32.3
Change due to pricing		48.4
Change due to operations and maintenance expenses		0.3
Operating margin, 2013		$	446.3

 

Higher gathering, processing and transportation volumes were responsible for an increase in operating margin of $32.3 million for the year ended December 31, 2013 compared to the year ended December 31, 2012. Higher volumes were primarily the result of NGL production increasing 25%, resulting in $34.1 million of higher operating margin. The increase in NGL production was largely driven by higher inlet volumes at the Cana processing facility, improved efficiencies at the Cana and Bridgeport processing facilities and unplanned downtime impacting Midstream Holdings’ Bridgeport processing facility in 2012. The increase in NGL production was partially offset by slightly lower throughput volumes, primarily on the Predecessor’s East Johnson and Northridge gathering systems.

 

Changes in pricing led to an increase in operating margin of $48.4 million for the year ended December 31, 2013 compared to the year ended December 31, 2012. Natural gas pipeline fees increased 15 %, which resulted in $44.2 million of additional revenues. Additionally, higher residue natural gas prices contributed an additional $32.4 million to operating margin. These increases were partially offset by lower margins of $28.2 million primarily due to NGL price declines.

 

Operations and maintenance expenses decreased $0.3 million, or 0%.

 

Other Operating Expenses, Net

 

Other operating expenses, net increased $19.0 million, or 7%, from the year ended December 31, 2012 to the year ended December 31, 2013, as summarized in the following schedule:

 

		2013			2012			Change
		(in millions)
Depreciation and amortization		$	199.0		$	159.8		$	39.2
General and administrative		47.0			43.6			3.4
Non-income taxes		18.0			13.2			4.8
Asset impairments		18.2			50.1			(31.9		)
Other, net		0.5			(3.0		)	3.5
Other operating expenses, net		$	282.7		$	263.7		$	19.0

 

Depreciation and amortization expense increased $39.2 million, or 25%, from 2012 to 2013. The increase primarily resulted from higher capitalized costs on the Cana system. Devon and other producers have continued to grow natural gas production in the Cana-Woodford Shale. As a result, we have increased our throughput capacity by expanding our pipeline and gathering systems and our Cana processing facility.

 

Historical general and administrative expenses consist of costs allocated by Devon for shared services that consist primarily of accounting, treasury, information technology, human resources, legal and facilities management. The costs were

 

 

allocated based on a proportionate share of Devon’s revenues, employee compensation and gross property, plant and equipment.

 

General and administrative expense increased $3.4 million, or 8%, primarily due to higher employee compensation and benefits.

 

Non-income tax expense consists primarily of ad valorem taxes. Non-income taxes increased $4.8 million, or 36%, from 2012 to 2013 primarily due to higher ad valorem tax assessments on Midstream Holdings’ Cana assets.

 

In 2013 and 2012, Devon recognized asset impairments of $18.2 million and $50.1 million, respectively. Devon determined that the carrying amounts of certain midstream facilities located in south and east Texas were not recoverable from estimated future cash flows due to declining dry natural gas production. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flows. None of the asset impairments in 2013 were related to assets that were contributed to Midstream Holdings.

 

During 2013 and 2012, our Predecessor recognized $0.5 million of net other expense and $3.0 million of net other income, respectively. In the second quarter of 2012, Predecessor received insurance proceeds of $5.6 million related to business interruption that occurred at Gulf Coast Fractionators.

 

Income Tax Expense. During 2013 and 2012, effective income tax rates were 36% for both periods. These rates differed from the U.S. statutory income tax rate due to the effect of state income taxes.

 

Discontinued Operations. The Predecessor has sold certain non-core assets that are presented as discontinued operations in the Predecessor’s historical financial statements. Net income from discontinued operations decreased $8.2 million from 2012 to 2013. The decrease was primarily due to the gain recognized on the divestiture of the West Johnson County processing facility and gathering system in 2012.

 

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

 

Operating Margin. Operating margin decreased $88.5 million, or 20%, from the year ended December 31, 2011 to the year ended December 31, 2012, as summarized in the following schedule:

 

		(in millions)
Operating margin, 2011		$	453.8
Change due to volumes		20.8
Change due to pricing		(93.8		)
Change due to operations and maintenance expenses		(15.5		)
Operating margin, 2012		$	365.3

 

Higher gathering, processing and transportation volumes were responsible for an increase in operating margin of $20.8 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. Residue volumes increased 7%, resulting in a $9.1 million increase to operating margin. The remainder of the operating margin increase resulted from higher natural gas gathered volumes and NGL production, which increased 3% and 2%, respectively. These volume increases primarily resulted from the restart of Midstream Holdings’ Cana processing facility following tornado damage in 2011, higher volumes on Midstream Holdings’ East Johnson County gathering system and continued development of the liquids-rich areas in the Cana-Woodford and Barnett Shales.

 

Changes in pricing led to a decrease in operating margin of $93.8 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. Lower NGL and residue natural gas prices reduced operating margin by $71.0 million and $42.8 million, respectively. These decreases were partially offset by higher gathering and compression fees which increased $20.0 million, or 9%.

 

Operations and maintenance expenses increased $15.5 million, or 10%, partially due to higher volumes, including the Cana system expansion. Expenses also increased due to repair and testing activities that were required on Midstream Holdings’ Bridgeport gathering systems in 2012.

 

 

Other Operating Expenses, Net.  Other operating expenses, net increased $121.5 million, or 85%, from the year ended December 31, 2011 to the year ended December 31, 2012, as summarized in the following schedule:

 

		2012			2011			Change
		(in millions)
Depreciation and amortization		$	159.8		$	144.8		$	15.0
General and administrative		43.6			40.1			3.5
Non-income taxes		13.2			15.3			(2.1		)
Asset impairments		50.1			—			50.1
Other, net		(3.0		)	(58.0		)	55.0
Other operating expenses, net		$	263.7		$	142.2		$	121.5

 

Depreciation and amortization expense increased $15.0 million, or 10%, from 2011 to 2012. The increase primarily resulted from higher capitalized costs on the Cana system. Devon and other producers have continued to grow natural gas production in the Cana-Woodford Shale. As a result, Midstream Holdings increased throughput capacity by expanding its pipeline and gathering systems and our Cana processing facility.

 

Historical general and administrative expenses consist of costs allocated by Devon for shared services that consist primarily of accounting, treasury, information technology, human resources, legal and facilities management. The costs were allocated based on a proportionate share of Devon’s revenues, employee compensation and gross property, plant and equipment.

 

General and administrative expense increased $3.5 million, or 9%, from 2011 to 2012, primarily due to higher employee compensation and benefits.

 

Non-income tax expense consists primarily of ad valorem taxes. Non-income taxes decreased $2.1 million, or 14%, from 2011 to 2012 primarily due to lower ad valorem tax assessments on Midstream Holdings’ Barnett assets.

 

The following schedule summarizes asset impairments recognized in 2012. There were no asset impairments in 2011. Due to declining natural gas production resulting from low natural gas and NGL prices, Midstream Holdings’ determined that the carrying amounts of certain of the Predecessors’ midstream assets, including the Northridge system, were not recoverable from estimated future cash flows. Consequently, the Northridge system and other assets of the Predecessor were written down to their estimated fair values, which were determined using discounted cash flow models.

 

		2012
		(in millions)
Northridge		$	16.4
Other assets not being contributed to Midstream Holdings		33.7
Total asset impairments		$	50.1

 

During 2012 and 2011, the Predecessor recognized $3.0 million and $58.0 million of net other income, respectively. In 2012, the Predecessor received insurance proceeds of $5.6 million related to business interruption that occurred at Gulf Coast Fractionators. In 2011, the Predecessor received $57.8 million of excess insurance recoveries related to business interruption and equipment damage at the Cana system that resulted from tornadoes.

 

Income Tax Expense. During 2012 and 2011, Midstream Holdings’ effective income tax rates were 36% for both periods. These rates differed from the U.S. statutory income tax rate due to the effect of state income taxes.

 

 

Discontinued Operations.  Net income from discontinued operations decreased $1.2 million from 2011 to 2012. The decrease was due to lower operating earnings subsequent to the divestiture of the West Johnson County processing facility and gathering system in 2012, partially offset by the $8.3 million gain recognized on the divestiture.

 

Liquidity and Capital Resources

 

Midstream Holdings’ Sources and Uses of Cash

 

The following schedule presents Midstream Holdings’ sources and uses of cash:

 

		Year Ended December 31,
		2013			2012			2011
Continuing operations:
Operating cash flow		$	360.5		$	254.4		$	401.2
Capital expenditures		(243.1		)	(351.7		)	(247.6		)
Contributions from (distributions to) owners		(117.6		)	115.7			(131.1		)
Other, net		0.2			(18.4		)	(22.5		)
Net change in cash		—			—			—
Discontinued operations:
Operating cash flow		1.8			25.3			33.4
Divestiture proceeds		155.1			87.6			—
Capital expenditures		(2.1		)	(13.5		)	(22.5		)
Contributions from (distributions to) owners		(170.4		)	(91.9		)	(34.8		)
Net change in cash		(15.6		)	7.5			(23.9		)
Total change in cash		$	(15.6	)	$	7.5		$	(23.9	)

 

Midstream Holdings’ Sources and Uses of Cash—Continuing Operations. Operating cash flow has been a significant source of liquidity. Generally, operating cash flow will increase or decrease due to the same factors that cause increases and decreases in operating margin. Consequently, changes in operating cash flow since 2011 are primarily driven by the fluctuations in volume and price described previously in results of operations.

 

Historically, operating cash flow has been used to fund capital expenditures. Since 2011, the Predecessor completed several capital expansion activities, including the expansions of the Cana system and Barnett assets in 2013.

 

Because Midstream Holdings’ continuing operations had no separate cash accounts, the owner contributions and distributions represent the net amount of all transactions that were settled with adjustments to equity.

 

Other, net uses and sources since 2011 largely pertain to the Predecessor’s equity investment in Gulf Coast Fractionators. During the years ended December 31, 2012 and 2011, the Predecessor made contributions related to this investment of $16.8 million and $21.1 million, respectively.

 

Midstream Holdings’ Sources and Uses of Cash—Discontinued Operations. Operating cash flow has decreased since 2011 largely due to declining throughput resulting from asset divestitures. In 2013, the Predecessor sold its controlling interest in its assets and operations located in Wyoming for approximately $148 million. In 2012, the Predecessor sold the West Johnson County system for $87 million. The Predecessor also received proceeds in 2013 and 2010 for other minor divestitures. These divestitures also contributed to the general decline in capital expenditures since 2011.

 

During the years ended 2013 and 2011, the Predecessor made cash distributions to non-controlling interests of $2.9 million, $5.4 million, respectively. During the year ended 2012, the Predecessor received cash contributions from non-controlling interests of $2.3 million, respectively. The remaining owner contributions and distributions in the table above represent the net amount of all other transactions that were settled with adjustments to equity.

 

 

Off-Balance Sheet Arrangements.    We had no off-balance sheet arrangements as of December 31, 2013, 2012 and 2011.

 

Contractual Obligations

 

A summary of contractual obligations as of December 31, 2013 is provided in the following table:

 

		Payments Due by Period
		Total			Less Than 1 Year			1-3 Years			3-5 Years			More Than 5 Years
		(in millions)
Lease obligations (1)		$	8.1		$	7.4		$	0.7		$	—		$	—
Rights-of-way (2)		1.0			0.1			0.2			0.2			0.5
Purchase commitments (3)		3.9			3.9			—			—			—
Asset retirement obligations (4)		14.9			0.1			0.1			0.1			14.6
Total		$	28.0		$	11.6		$	1.0		$	0.3		$	15.1

 

(1)                  Lease obligations consist of non-cancelable operating leases for equipment and office space used in daily operations.

(2)                  Right-of-way payments are estimated to approximate $0.1 million per year for the next ten years. Payments for rights-of-way will be required as long as Midstream Holdings’ systems are in use, which may be more or less than the ten years we have assumed for this disclosure.

(3)                  Purchase commitments include commitments to purchase materials in connection with Midstream Holdings’ projects to construct new facilities or expand existing facilities.

(4)                  Asset retirement obligations represent the estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on Midstream Holdings’ December 31, 2013 balance sheet.

 

Capital Requirements

 

Our 2014 capital budget includes approximately $300.0 million of identified growth projects including capitalized interest. Our primary capital projects for 2014 include the expansion of the Cajun-Sibon NGL Pipeline Phase II and construction of our Bearkat plant facilities. During 2013, we invested in several capital projects which primarily included the expansion of the Cajun-Sibon NGL Pipeline. See “Exhibit 99.1. Business—Recent Growth Developments” for further details.

 

We expect to fund our 2014 maintenance capital expenditures of approximately $65.0 million from operating cash flows. We expect to fund the growth capital expenditures from the proceeds of borrowings under our credit facility discussed below and proceeds from other debt and equity sources.  In 2014, it is possible that not all of the planned projects will be commenced or completed. Our ability to pay distributions to our unitholders, and to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond our control.

 

Indebtedness

 

Credit Facility.    On February 20, 2014, we entered into a new $1.0 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “credit facility”).  The new credit facility replaced our previous credit facility.  The credit facility will mature on the fifth anniversary of the initial funding date, which was March 7, 2014, unless we request, and the requisite lenders agree, to extend it pursuant to its terms.  The credit facility contains certain financial, operational and legal covenants.  Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the credit facility, which definition includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0.  If we consummate one or more acquisitions in which the aggregate purchase price is $50.0 million or more, the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA will increase to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

 

Borrowings under the credit facility bear interest at our option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin.  The applicable margins vary depending on our credit rating.  Upon breach by us of certain covenants governing the credit facility, amounts outstanding under the credit facility, if any, may become due and payable immediately.

 

 

Senior Unsecured Notes.    On February 10, 2010, we issued, together with Crosstex Energy Finance Corporation, $725.0 million in aggregate principal amount of 8.875% senior unsecured notes (the “2018 Notes”) due on February 15, 2018 at an issue price of 97.907% to yield 9.25% to maturity including the original issue discount (OID).  Interest payments on the 2018 Notes are due semi-annually in arrears in February and August.  On May 24, 2012, we issued, together with Crosstex Energy Finance Corporation,  $250.0 million in aggregate principal amount of 7.125% senior unsecured notes (the “2022 Notes” and together with the 2018 Notes, the “Senior Notes”) due on June 1, 2022 at an issue price of 100% of the principal amount to yield 7.125% to maturity. The interest payments on the 2022 Notes are due semi-annually in arrears in June and December.

 

The indentures governing the Senior Notes contain covenants that, among other things, limit our ability to:

 

·                  sell assets including equity interests in our subsidiaries;

 

·                  pay distributions on, redeem or repurchase units or redeem or repurchase our subordinated debt (as discussed in more detail below);

 

·                  make investments;

 

·                  incur or guarantee additional indebtedness or issue preferred units;

 

·                  create or incur certain liens;

 

·                  consolidate, merge or transfer all or substantially all of our assets;

 

·                  engage in transactions with affiliates;

 

·                  enter into sale and leaseback transactions; or

 

·                  engage in certain business activities.

 

The indentures provide that if our fixed charge coverage ratio (the ratio of consolidated cash flow to fixed charges, which generally represents the ratio of adjusted EBITDA to interest charges with further adjustments as defined per the indenture) for the most recently ended four full fiscal quarters is not less than 2.0 to 1.0, we will be permitted to pay distributions to our unitholders in an amount equal to available cash from operating surplus (each as defined in our partnership agreement) with respect to our preceding fiscal quarter plus a number of items, including the net cash proceeds received by us as a capital contribution or from the issuance of equity interests since the date of the indenture, to the extent not previously expended. If our fixed charge coverage ratio is less than 2.0 to 1.0, we will be able to pay distributions to our unitholders in an amount equal to a specified basket (less amounts previously expended pursuant to such basket), plus the same number of items discussed in the preceding sentence to the extent not previously expended. We expect to be in compliance with this covenant for at least the next twelve months.

 

If the Senior Notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services, many of the covenants discussed above will terminate.

 

We may redeem all or a part of the 2018 Notes at redemption prices (expressed as percentages of principal amount) equal to 104.438% for the twelve-month period beginning on February 15, 2014, 102.219% for the twelve-month period beginning February 15, 2015 and 100.00% for the twelve-month period beginning on February 15, 2016 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the notes.

 

We may redeem up to 35% of the 2022 Notes at any time prior to June 1, 2015 in an amount not greater than the cash proceeds from one or more equity offerings at a redemption price of 107.125% of the principal amount of the 2022 Notes (plus accrued and unpaid interest to the redemption date) provided that

 

·                  at least 65% of the aggregate principal amount of the 2022 Notes remains outstanding immediately after the occurrence of such redemption; and

 

·                  the redemption occurs within 180 days of the date of the closing of the equity offering.

 

 

Pursuant to the foregoing, on January 3, 2014, we instructed the trustee to deliver a notice of redemption for approximately $53.5 million in aggregate principal amount of the 2022 Notes (the “Redeemed Notes”), representing approximately 21% of the aggregate principal amount of the outstanding 2022 Notes.  The Redeemed Notes were redeemed effective as of February 2, 2014 for a total redemption price equal to $1,083 per $1,000 principal amount redeemed.  Following the completion of the redemption, approximately $196.5 million aggregate principal amount of the 2022 Notes remain outstanding.

 

Prior to June 1, 2017, we may redeem all or a part of the remaining 2022 Notes at the redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest to the redemption date.

 

On or after June 1, 2017, we may redeem all or a part of the remaining 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.563% for the twelve-month period beginning on June 1, 2017, 102.375% for the twelve-month period beginning on June 1, 2018, 101.188% for the twelve-month period beginning on June 1, 2019 and 100.000% for the twelve-month period beginning on June 1, 2020 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes.

 

Each of the following is an event of default under the indentures:

 

·                  failure to pay any principal or interest when due;

 

·                  failure to observe any other agreement, obligation or other covenant in the indenture, subject to the cure periods for certain failures;

 

·                  our default under other indebtedness that exceeds a certain threshold amount;

 

·                  failures by us to pay final judgments that exceed a certain threshold amount; and

 

·                  bankruptcy or other insolvency events involving us.

 

If an event of default relating to bankruptcy or other insolvency events occurs, the Senior Notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the Senior Notes may accelerate the maturity of the Senior Notes and exercise other rights and remedies.

 

Successful completion of the Acquisition triggered a mandatory repurchase offer under the terms of the indenture governing the 2018 Notes at a purchase price equal to 101% of the aggregate principal amount of the 2018 Notes repurchased, plus accrued and unpaid interest, if any. In certain circumstances, the completion of the business combination also could trigger a mandatory repurchase offer under the terms of the indenture the 2022 Notes if, within 90 days of consummation of the transactions, we experience a rating downgrade of the 2022 Notes by either Moody’s or S&P.  We intend to fulfill our obligations with respect to the mandatory repurchase offer of the 2018 Notes and, if necessary, the 2022 Notes, in accordance with the terms of the applicable indenture.

 

Certain Relationships and Related Party Transactions

 

Our General Partner.  Our General Partner does not receive any management fee or other compensation in connection with its management of our business, but it is reimbursed for all direct and indirect expenses incurred on our behalf.

 

Our General Partner owns the general partner interest in us and all of our incentive distribution rights. Our General Partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our General Partner is entitled to 13.0% of amounts we distribute in excess of $0.25 per unit, 23% of the amounts we distribute in excess of $0.3125 per unit and 48.0% of amounts we distribute in excess of $0.375 per unit.

 

Relationship with Devon and ENLC.  ENLC indirectly owns 16,414,830 common units, representing an approximate 7.1% limited partnership interest in us as of March 7, 2014. ENLC also indirectly owns our General Partner and has the power to appoint all of the officers and directors of our General Partner.  ENLC is managed by its managing member, which is wholly-owned by Devon.  Therefore, Devon indirectly controls our General Partner, which has the sole authority to

 

 

manage and operate our business.  Devon also indirectly owns 120,542,441 Class B units, representing an approximate 52% limited partnership interest in us as of March 7, 2014.  Accordingly, through its control of our General Partner and majority ownership of our outstanding equity interests, Devon effectively has the ability to veto some of our actions and to control our management.

 

Additionally, four of our directors, including John Richels, the chairman of our board of directors, David Hager, Thomas Mitchell and Darryl Smette, are officers of Devon.  Those individuals do not receive separate compensation for their service on our board of directors, but they are entitled to indemnification related to their service as directors pursuant to the indemnification agreements as described below.

 

Reimbursement of Costs.  ENLC pays us for administrative and compensation costs that we incur on its behalf. We anticipate that during 2014, this cost reimbursement will be between $12.0 million to $15.0 million.

 

Commercial Arrangements

 

Midstream Holdings, in which we hold a 50% economic interest as of March 7, 2014, conducts business with Devon pursuant to gathering and processing agreements described below.  We also historically have maintained a relationship with Devon as a customer, as described in more detail below.

 

Gathering and Processing Agreements

 

As described elsewhere, Midstream Holdings was previously a wholly-owned subsidiary of Devon, and all of its assets were contributed to it by Devon.  In connection with the consummation of the business combination, Midstream Holdings entered into gathering and processing agreements with certain subsidiaries of Devon pursuant to which Midstream Holdings provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon to Midstream Holdings gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering lands within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon.

 

Pursuant to the gathering and processing agreements, Devon has committed to deliver specified average minimum daily volumes of natural gas to Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales during each calendar quarter for a five-year period following execution. These commitments account for substantially all of Midstream Holdings’ natural gas supply and approximately 21.5% of our combined revenues, or $547.8 million, on a pro forma basis for the year ended December 31, 2013.  Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.

 

The gathering and processing agreements are fee-based, and Midstream Holdings is paid a specified fee per MMBtu for natural gas gathered on Midstream Holdings’ gathering systems and a specified fee for natural gas processed. The particular fees, all of which are subject to an automatic annual inflation escalator at the beginning of each year, differ from one system to another and do not contain a fee redetermination clause.

 

Please see “Exhibit 99.2—Risk Factors” for a description of the risks associated with our dependence on Devon pursuant to these agreements.

 

Historical Customer Relationship with Devon

 

As noted above, we have historically maintained a customer relationship with Devon pursuant to which certain of our subsidiaries provide gathering, transportation, processing and gas lift services to Devon subsidiaries in exchange for fee-based compensation under several agreements with such Devon subsidiaries.  The terms of these agreements vary, but the agreements expire between July 2014 and July 2021 and they automatically renew for month-to-month or year-to-year periods unless canceled by Devon prior to expiration.  In addition, one of our subsidiaries has agreements with a subsidiary of Devon pursuant to which our subsidiary purchases and sells NGLs and pays or receives, as applicable, a margin-based fee.  These NGL purchase and sale agreements have either month-to-month terms or expire in July 2014, depending on the agreement, but none renews automatically.  These historical agreements collectively comprise $72.2 million, or 2.8%, of combined revenue on a pro forma basis for the year ended December 31, 2013.

 

Transition Services Agreement

 

In connection with the consummation of the business combination, we entered into a transition services agreement with Devon pursuant to which Devon will provide certain services to us with respect to the business and operations of Midstream Holdings, including IT, accounting, pipeline integrity, compliance management and procurement services, and we will provide certain services to Devon and its subsidiaries, including IT, human resources and other commercial and operational services. We expect this agreement will have minimal to no impact on our annual revenue.

 

 

GCF Agreement

 

In connection with the consummation of the business combination, Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Devon agreed, from and after the closing of the business combination, to hold for the benefit of Midstream Holdings the economic benefits and burdens of Devon’s 38.75% general partner interest in Gulf Coast Fractionators in Mont Belvieu, Texas.  We expect this agreement to contribute approximately $12.0 million to our income from equity investments for fiscal year 2014.

 

Lone Camp Gas Storage Agreement

 

In connection with the consummation of the business combination, Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon under which Midstream Holdings will provide gas storage services at its Lone Camp storage facility.  Under this agreement, the wholly-owned subsidiary of Devon will reimburse Midstream Services for the expenses it incurs in providing the storage services.  We expect this agreement will have minimal to no impact on our annual revenue.

 

Acacia Transportation Agreement

 

In connection with the consummation of the business combination, a subsidiary of Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Midstream Holdings provides transportation services to Devon on its Acacia line.  This agreement accounted for approximately 0.6% of our combined revenues, or $14.4 million, on a pro forma basis for the year ended December 31, 2013.

 

Office Leases

 

In connection with the consummation of the business combination, we entered into three office lease agreements with a wholly-owned subsidiary of Devon pursuant to which we will lease office space at Devon’s Bridgeport, Oklahoma City and Cresson office buildings.  Rent payable to Devon under these lease agreements is $174,000, $31,000 and $66,000, respectively, on an annual basis.

 

Preferential Rights Agreement

 

Upon the closing of the business combination, we entered into a preferential rights agreement with ENLC and CEI, pursuant to which ENLC and CEI granted us a right of first refusal, for a period of 10 years, with respect to (i) CEI’s interest in E2, and (ii) Devon’s 50% interest in the Access Pipeline transportation system (the “Access Pipeline Interest”), to the extent ENLC in the future obtains such interest pursuant to a first offer agreement between Devon and ENLC. In addition, if ENLC has the opportunity to exercise its right of first offer for the Access Pipeline Interest pursuant to the first offer agreement but determines not to exercise such right, it will be required to assign such right to us.

 

Tax Sharing Agreement

 

In connection with the Contribution Closing, the Partnership, ENLC and Devon entered into a tax sharing agreement providing for the allocation of responsibilities, liabilities and benefits relating to any tax for which a combined tax return is due. In 2013, ENLC and Devon incurred approximately $3.0 million in taxes that would have been subject to the tax sharing agreement, had it been effective.

 

Indemnification of Directors and Officers

 

Under our partnership agreement, in most circumstances, we will, to the fullest extent permitted by law, indemnify and hold harmless the following persons from and against all losses, claims, damages or similar events:

 

·                  our General Partner;

 

·                  any departing general partner;

 

·                  any person who is or was an affiliate of our General Partner or any departing general partner;

 

·                  any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

 

 

·                  any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our General Partner or any departing general partner; and

 

·                  any person designated by our General Partner.

 

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our General Partner will not be liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification.  We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

 

We have entered into indemnification agreements (the “Indemnification Agreements”) with each of our General Partner’s directors and executive officers (collectively, the “Indemnitees”).  Under the terms of the Indemnification Agreements, we agree to indemnify and hold each Indemnitee harmless, subject to certain conditions, against any and all losses, claims, damages, liabilities, expenses (including legal fees and expenses), judgments, fines, ERISA excise taxes, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals (each, a “Proceeding”), in which the Indemnitee is involved, or is threatened to be involved, as a party or otherwise, because the Indemnitee is or was a director, manager or officer of the General Partner or us, or is or was serving at the request of the General Partner or us as a manager, managing member, general partner, director, officer, fiduciary, or trustee of another entity, organization or person of any nature. To the extent that a change in the laws of the State of Delaware permits greater indemnification under any statute, agreement, organizational document or governing document than would be afforded under the Indemnification Agreements as of the date of the Indemnification Agreements, the Indemnitee shall enjoy the greater benefits so afforded by such change.

 

Approval and Review of Related Party Transactions.  If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the Board or our senior management, as appropriate. If the Board is involved in the approval process, it determines whether it is advisable to refer the matter to the Conflicts Committee of the Board, comprised entirely of independent directors, as constituted under our limited partnership agreement. The Conflicts Committee operates pursuant to its written charter and our partnership agreement. If a matter is referred to the Conflicts Committee, the Conflicts Committee obtains information regarding the proposed transaction from management and determines whether it is advisable to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. If the committee retains such counsel or financial advisor, it considers the advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.

 

Disclosure Regarding Forward-Looking Statements

 

This report contains forward-looking statements that are based on information currently available to management as well as management’s assumptions and beliefs. All statements, other than statements of historical fact, included herein constitute forward-looking statements, including but not limited to statements identified by the words “forecast,” “may,” “believe,” “will,” “should,” “plan,” “predict,” “anticipate,” “intend,” “estimate” and “expect” and similar expressions. Such statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to the specific uncertainties discussed elsewhere in this report, the risk factors set forth in “Exhibit 99.2 Risk Factors” may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.