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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

(a) Management's Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management of the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.

Cash and Cash Equivalents

(b) Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Natural Gas and Natural Gas Liquids Inventory

Inventories of products consist of natural gas, NGLs, crude oil and condensate. The Company reports these assets at the lower of cost or market.

Property, Plant, and Equipment

(d) Property, Plant, and Equipment

Property, plant and equipment consist of intrastate gas transmission systems, gas gathering systems, NGL, condensate and crude oil pipelines, natural gas processing plants, NGL fractionation plants and brine disposal wells. Gas required to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Other property and equipment is primarily comprised of the ORV trucking fleet, computer software and equipment, furniture, fixtures, leasehold improvements and office equipment. Property, plant and equipment are recorded at cost. Repairs and maintenance are charged against income when incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. Interest costs are capitalized to property, plant and equipment during the period the assets are undergoing preparation for intended use. Interest costs totaling $24.5 million, $4.0 million and $0.9 million were capitalized for the years ended December 31, 2013, 2012 and 2011, respectively.

Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows:



		Useful Lives
Transmission assets		20 - 30 years
Gathering systems		15 - 20 years
Gas processing plants		20 years
Other property and equipment		3 - 15 years

Depreciation expense of $99.8 million, $98.2 million and $77.8 million was recorded for the years ended December 31, 2013, 2012 and 2011, respectively. Depreciation expense also includes the amortization of assets classified as capital lease assets.

Goodwill and Intangible Assets

(e) Goodwill and Intangible Assets

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Partnership evaluates goodwill for impairment annually as of July 1, 2013, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Partnership first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step process goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss.

The Partnership has approximately $153.8 million and $152.6 million of goodwill at December 31, 2013 and 2012, respectively, related to the acquisition of Clearfield Energy, Inc. and its wholly-owned subsidiaries (collectively, "Clearfield") in July 2012. The goodwill recognized from the Clearfield acquisition results primarily from the value of opportunity created from the strategic asset positioning in the Utica and Marcellus shale plays which provides the Partnership with a substantial growth platform in a new geographic area. The goodwill is allocated to the ORV segment. There were no impairment charges resulting from the Partnership's July 1, 2013 impairment testing, and no event indicating impairment has occurred subsequent to that date.

Intangible assets consist of customer relationships and the value of the dedicated and non-dedicated acreage attributable to pipeline, gathering and processing systems. Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from three to twenty years. The intangible assets associated with dedicated and non-dedicated acreage attributable to pipeline, gathering and processing systems are being amortized using the units of throughput method of amortization.

The following table represents the Partnership's total purchased intangible assets at years ended December 31, 2013 and 2012 (in thousands)



	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
2013
Customer relationships (1)	$	148,456	$	(65,125	)	$	83,331
Dedicated and non-dedicated acreage	395,649		(162,758		)	232,891
Total	$	544,105	$	(227,883	)	$	316,222
2012
Customer relationships	$	292,658	$	(130,458	)	$	162,200
Dedicated and non-dedicated acreage	395,652		(132,847		)	262,805
Total	$	688,310	$	(263,305	)	$	425,005

(1) See Note 4-"Acquisition, Disposition and Impairments" for information related to an impairment on the Partnership's Eunice customer relationships in 2013.

The weighted average amortization period for intangible assets is 19.0 years. Amortization expense for intangibles was approximately $40.5 million, $64.1 million and $47.5 million for the years ended December 31, 2013 , 2012 and 2011, respectively.

The following table summarizes the Partnership's estimated aggregate amortization expense for the next five years (in thousands):



2014	$	35,827
2015	34,430
2016	32,944
2017	32,269
2018	31,882
Thereafter	148,870
Total	$	316,222

Investment in Limited Liability Company

(f) Investment in Limited Liability Company

On June 22, 2011, the Partnership entered into a limited liability agreement with Howard Energy Partners ("HEP") for an initial capital contribution of $35.0 million in exchange for an individual ownership interest in HEP. In 2013 and 2012, the Partnership made additional capital contributions of $30.6 million and $52.3 million, respectively. Additionally, the Partnership received a distributions of $17.5 million in 2013. HEP owns midstream assets and provides midstream services to Eagle Ford Shale producers. The Partnership owns 30.6 percent of HEP and accounts for this investment under the equity method of accounting. In December 2013, Alinda Capital Partners acquired a 59% capital interest in HEP from Quanta Capital Solutions and GE Energy Financial Services. This investment is reflected on the balance sheet as "Investment in limited liability company." The Partnership's proportional share of earnings is recorded as an increase to this investment account and recorded as equity in income of limited liability company.

Joint Venture Investment

(g) Investment in E2

In March 2013, the Company entered into an agreement to form E2 Energy Services, LLC and E2 Appalachian Compression, LLC ("E2"), which are companies that provide compression and stabilization services for producers in the liquids-rich window of the Utica Shale play. The Company owns approximately 93.7% of E2 Energy Services, LLC and a 92.5% interest in E2 Appalachian Compression, LLC and has pre-determined rights to purchase the management ownership interests of E2 in the future. The Company owns a majority interest in E2 and consolidates its investment in E2 pursuant to Financial Accounting Standards Board ("FASB") ASC 810-10-05-08. The Company has committed to invest of approximately $76.0 million in E2 to fund the construction of three new natural gas compression and condensate stabilization facilities, which E2 will own and operate. The facilities are located in Noble and Monroe counties in the southern portion of the Utica Shale play in Ohio. As of December 31, 2013, the Company has invested $60.7 million in E2. Commercial operations of the first facility began during the first quarter of 2014 and the remaining plants are expected to be operational during the first half of 2014.

Other Assets

(h) Other Assets

Unamortized debt issuance costs totaling $22.8 million and $26.0 million as of December 31, 2013 and 2012, respectively, are included in other assets, net. Debt issuance costs are amortized into interest expense using the straight-line method over the term of the debt.

Gas Imbalance Accounting

(i) Gas Imbalance Accounting

Quantities of natural gas and NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas or NGLs. The Company had imbalance payables of $4.8 million and $2.3 million at December 31, 2013 and 2012, respectively, which approximate the fair value of these imbalances. The Company had imbalance receivables of $4.2 million and $1.5 million at December 31, 2013 and 2012, respectively, which are carried at the lower of cost or market value.

Asset Retirement Obligations

(j) Asset Retirement Obligations

FASB ASC 410-20-25-16 was issued in March 2005 and became effective at December 31, 2005. FASB ASC 410-20-25-16 clarifies that the term "conditional asset retirement obligation" as used in FASB ASC 410-20, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FASB ASC 410-20-25-16 provides that a liability for the fair value of a conditional asset retirement activity should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FASB ASC 410-20-25-16 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation under FASB ASC 410-20. The Company provided an asset retirement obligation of $0.5 million and $0.5 million as of December 31, 2013 and 2012, respectively,

Revenue Recognition

(k) Revenue Recognition

The Company recognizes revenue for sales or services at the time the natural gas, NGLs, condensate or crude oil are delivered or at the time the service is performed. The Company generally accrues one month of sales and the related gas, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent months. Actual results could differ from the accrual estimates. Purchase and sale arrangements are generally reported in revenues and costs on a gross basis in the consolidated statement of operations in accordance with FASB ASC 605-45-45-1. Except for fee based arrangements, the Partnership acts as the principal in these purchase and sale transactions, has the risk and reward of ownership as evidenced by title transfer, schedules the transportation and assumes credit risk. The Partnership conducts "off-system" gas marketing operations as a service to producers on systems that it does not own. It refers to these activities as part of energy trading activities. In some cases, the Partnership earns an agency fee from the producer for arranging the marketing of the producer's natural gas. In other cases, the Partnership purchases the natural gas from the producer and enters into a sales contract with another party to sell the natural gas. The revenue and cost of sales for these activities are included in revenue on a net basis in the consolidated statement of operations.

The Company accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).

Derivatives

The Partnership uses derivatives to hedge against changes in cash flows related to product price, as opposed to their use for trading purposes. FASB ASC 815 requires that all derivatives be recorded on the balance sheet at fair value. It generally determines the fair value of futures contracts and swap contracts based on the difference between the derivative's fixed contract price and the underlying market price at the determination date. The asset or liability related to the derivative instruments is recorded on the balance sheet in fair value of derivative assets or liabilities.

Realized and unrealized gains and losses on commodity related derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, are recorded as gain or loss on derivatives in the consolidated statement of operations in the period incurred. Unrealized gains and losses on effective cash flow hedge derivatives are recorded as a component of accumulated other comprehensive income. When the hedged transaction occurs, the realized gain or loss on the hedge derivative is transferred from accumulated other comprehensive income to earnings. Realized gains and losses on commodity hedge derivatives are recognized in revenues. Settlements of derivatives are included in cash flows from operating activities.

Comprehensive Income, Policy

(l) Comprehensive Income (Loss)

Comprehensive income includes net income (loss) and other comprehensive income, which includes unrealized gains and losses on derivative financial instruments. Pursuant to FASB ASC 815, the Company records deferred hedge gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income.

In February 2013, the FASB issued ASU 2013-2, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income ("ASU 2013-2”). ASU 2013-2 requires disclosure of amounts reclassified out of accumulated other comprehensive income ("AOCI") by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income but only if the amount reclassified is required to be reclassified to net income in its entirety in the same reporting period. For amounts not reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts. For the years ended December 31, 2013, 2012 and 2011, we reclassified cash flow hedge (gains) losses in the amounts of $(1.0) million, $(0.6) million and $1.8 million, respectively, included in other comprehensive income to revenues on the consolidated statements of operations.

Legal Costs Expected to be Incurred

Legal Costs Expected to be Incurred in Connection with a Loss Contingency

Legal costs incurred in connection with a loss contingency are expensed as incurred.

Concentrations of Credit Risk

(n) Concentrations of Credit Risk

Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist primarily of trade accounts receivable and derivative financial instruments. Management believes the risk is limited since the Partnership's customers represent a broad and diverse group of energy marketers and end users. In addition, the Partnership continually monitors and reviews credit exposure to its marketing counter-parties and letters of credit or other appropriate security are obtained as considered necessary to limit the risk of loss. The Partnership's records reserves for uncollectible accounts on a specific identification basis since there is not a large volume of late paying customers. The Partnership had a reserve for uncollectible receivables as of December 31, 2013 and 2012 of $0.6 million and $0.5 million, respectively.

During the years ended December 31, 2013, 2012, and 2011, the Partnership had only one customer that individually represented greater than 10.0% of its revenues. The customer is located in the LIG segment and represented 12.6%, 10.5% and 12.3% of consolidated revenue for each of the years ended December 31, 2013, 2012 and 2011, respectively.

Environmental Costs

(p) Environmental Costs

Environmental expenditures are expensed or capitalized as appropriate, depending on the nature of the expenditures and their future economic benefit. Expenditures that related to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (or a discounted basis when the obligation can be settled at fixed and determinable amounts) when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. For the years ended December 31, 2013, 2012 and 2011, such expenditures were not significant.

Share-Based Awards

(q) Share-Based Awards

The Company recognizes compensation cost related to all stock-based awards, including stock options, in its consolidated financial statements in accordance with FASB ASC 718. The Partnership and CEI each have similar unit or share-based payment plans for employees, which are described below. Share-based compensation associated with CEI's share-based compensation plans awarded to officers and employees of the general partner of the Partnership are recorded by the Partnership since CEI has no substantial or managed operating activities other than its interest in the Partnership. Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in thousands):



	Years Ended December 31,
	2013		2012		2011
Cost of share-based compensation charged to general and administrative expense	$	12,546	$	8,240	$	6,405
Cost of share-based compensation charged to operating expense	1,837		1,243		1,151
Total amount charged to income	$	14,383	$	9,483	$	7,556
Interest of non-controlling partners in share-based compensation	$	5,656	$	3,813	$	3,052
Amount of related income tax benefit recognized in income	$	3,235	$	2,102	$	1,670

Recent Accounting Pronouncements

(r) Recent Accounting Pronouncements

We have reviewed all recently issued accounting pronouncements that became effective during the year ended December 31, 2013, and have determined that none would have a material impact on our Consolidated Financial Statements.