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(Registrant’s telephone number, including area code)
Inergy Midstream, L.P.
Two Brush Creek Blvd., Suite 200
Kansas City, Missouri, 64112
September 30
(Former name)
(Former address)
(Former
fiscal year)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨
Indicate by check mark whether
the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that registrant was required to submit and post such files). Yes ý No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated
filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
¨
Accelerated filer
¨
Non-accelerated
filer
x (Do not check if a smaller reporting company)
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý
Inergy Midstream, LLC was formed in September 2004 by Inergy, L.P. (“Inergy”) to acquire, develop, own and operate midstream energy assets. In connection with its initial public offering (“IPO”) of common units representing limited partnership interests, (i) Inergy Midstream, LLC converted into a Delaware limited partnership and changed its name to Inergy Midstream, L.P. (the
“Company”) on November 14, 2011, and (ii) the Company transferred to Inergy 100% of its membership interest in two wholly owned subsidiaries (US Salt, LLC and Tres Palacios Gas Storage LLC) on November 25, 2011. The Company's common units began trading on the New York Stock Exchange (“NYSE”) on December 16, 2011 under the symbol “NRGM,” and the IPO closed on December 21, 2011.
Inergy
owns all of the Company's Incentive Distribution Rights (“IDRs”) which entitle it to receive 50% of all distributions by the Company in excess of the initial quarterly distribution of $0.37 per unit. IDRs, which represent a limited partnership ownership interest in the Company, are considered to be participating securities because they have the right to participate in earnings with common equity holders. Under the Company's partnership agreement, IDRs participate in net income only to the extent of the amount of cash distributions
actually declared, thereby excluding the IDRs from participating in undistributed earnings or losses. Accordingly, the undistributed net income is allocated to the other ownership interests on a pro-rata basis. Inergy indirectly owns the Company's general partnership interest, which entitles the general partner to management but no economic rights in the Company.
On September 27, 2013, the Inergy Midstream Board of Directors approved an amendment to the First Amended and Restated Agreement of Limited Partnership of the Partnership (“Amendment No. 1”), to be effective as of September 27, 2013. Amendment
No. 1 changes the fiscal year end of the Partnership from September 30 to December 31. Amendment No. 1 was filed on Form 8-K on October 1, 2013. These financial statements are being filed as part of a transition report on Form 10-Q covering the transition period that began October 1, 2012 and ended December 31, 2012. The comparative three-month period ended December 31, 2011 has also been presented.
On October 7, 2013, Inergy Midstream completed the merger (the "Crestwood Merger") of its wholly-owned subsidiary and Crestwood Midstream Partners LP ("Legacy CMLP"), with Legacy CMLP continuing as the surviving entity. Immediately
following the closing of the Crestwood Merger, on October 7, 2013, (i) Legacy CMLP merged with and into Inergy Midstream, with Inergy Midstream continuing as the surviving entity, and (ii) Inergy Midstream changed its name to Crestwood Midstream Partners LP and changed its NYSE listing symbol to “CMLP". We refer to the renamed partnership as Inergy Midstream in this transition report.
NRGM GP, LLC Change of Control Event
In connection with the IPO, Inergy and Inergy Holdings GP, LLC (“Holdings GP”), the indirect owner of Inergy's general partner, entered into a membership interest purchase agreement under which, under certain circumstances, Holdings GP will be required to purchase from Inergy, and Inergy will be required
to sell to Holdings GP, all of the membership interests in MGP GP, LLC, the entity that controls the Company's general partner, for nominal consideration. MGP GP, LLC is a wholly owned subsidiary of Inergy and the general partner of Inergy Midstream Holdings, L.P., which is the sole member of the Company's general partner and direct holder of all of its incentive distribution rights. Under the agreement, Holdings GP is required to purchase MGP GP, LLC in the event that (i) a change of control of Inergy occurs at a time when Inergy is entitled to receive less than 50% of all cash distributed with respect to the Company's limited partner interests and incentive distribution
rights or (ii) through dilution or a distribution to the Inergy common unitholders of Inergy's interests in us. Inergy is entitled to receive less than 25% of all cash distributed with respect to the Company's limited partner interests and incentive distribution rights.
Nature of Operations
The Company's financial statements reflect three operating and reporting segments: storage and transportation operations, salt operations and crude operations. The
Company's storage and transportation operations are engaged primarily in the storage and transportation of natural gas and natural gas liquids (“NGLs”). Its operations are currently concentrated in the Northeast region of the United States. The Company's salt operations, which are located in New York, include the production and sale of salt products by US Salt, LLC ("US Salt"). US Salt is one of five major solution mined salt manufacturers in the United States,
producing evaporated salt products for food, industrial, pharmaceutical and water conditioning uses. The Company's crude operations, which were acquired in December 2012, include the COLT crude oil loading terminal, storage facility and interconnecting pipeline facilities ("COLT Hub") located in North Dakota. See Note 4 for additional information about this acquisition.
The Company owns and operates the following storage facilities:
•
Stagecoach,
a 26.25 Bcf multi-cycle depleted reservoir natural gas storage facility located approximately 150 miles northwest of New York City in Tioga County, New York and Bradford County, Pennsylvania;
•
Thomas Corners, a 7.0 Bcf multi-cycle depleted reservoir natural gas storage facility located in Steuben County, New York;
•
Steuben, a 6.2
Bcf single-turn depleted reservoir natural gas storage facility located in Steuben County, New York;
•
Seneca Lake, a 1.45 Bcf multi-cycle salt dome reservoir natural gas storage facility located in Schuyler County, New York; and
•
Bath, a 1.5 million barrel NGL storage facility located near Bath, New York.
The
Company owns and operates natural gas transportation assets in the Northeast, including:
•
the compression and appurtenant facilities installed to expand transportation capacity on the Stagecoach north and south laterals (the “North-South Facilities”), which provide 325 MMcf/d of firm interstate transportation service to shippers;
•
the MARC I Pipeline, a 39-mile,
30-inch interstate natural gas pipeline that extends from the Company's Stagecoach south lateral interconnect with TGP's 300 Line and Transco's Leidy Line, and capable of providing 550 MMcf/d of firm transportation service to shippers; and
•the East Pipeline, a 37.5-mile, 12-inch diameter intrastate natural gas pipeline in New York.
The Company also owns US Salt, a solution mined salt production facility located on the shores of Seneca
Lake outside of Watkins Glen, New York. The solution mining process used by US Salt creates salt caverns that can be developed into usable natural gas and NGL storage capacity.
In December 2012, the Company acquired the COLT Hub, which is strategically located near the town of Epping in Williams County, North Dakota, in the heart of the Bakken and Three Forks shale oil-producing areas. With 720,000 barrels of crude oil storage and two 8,700-foot rail loops, the COLT Hub can accommodate 120-car unit trains and is capable of loading up to 120,000 barrels per day
by rail. COLT’s customers can source product via the eight-bay truck unloading rack, the COLT Connector, a 21-mile, 10-inch bi-directional pipeline that connects the COLT Hub to the Enbridge and Tesoro pipelines at Dry Fork (Beaver Lodge/Ramberg junction), the Banner gathering system, and a planned connection to the Bear Tracker Energy gathering system.
Basis of Presentation
The financial information contained herein as of December 31, 2012, and for the three-month periods ended December 31,
2012 and 2011, is unaudited. The Company believes this information has been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and Article 10 of Regulation S-X. The Company also believes this information includes all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the financial position, results of operations and cash flows for the periods then ended.
On May 14, 2012, the
Company acquired 100% of the membership interests in US Salt from Inergy. The US Salt acquisition is reflected in the Company's consolidated financial statements based on the historical values, and periods prior to the acquisition have been retrospectively adjusted to include the historical balances of US Salt. This accounting treatment is similar to the pooling of interests and is required as the transaction is amongst entities under common control.
The accompanying consolidated financial statements include the accounts of Inergy Midstream, L.P. (formerly Inergy Midstream, LLC) and its wholly owned subsidiaries, including among others Arlington Storage Company, LLC (“Arlington”), Central New York Oil And Gas Company, L.L.C. (“CNYOG”), Finger Lakes LPG Storage, LLC (“Finger Lakes”), Inergy Gas Marketing, LLC, Inergy Pipeline East, LLC, US Salt, Inergy Crude Logistics, LLC (formerly Rangeland Energy, LLC), NRGM Finance Corp., and Inergy Storage, Inc. All significant intercompany transactions, including distribution income, and balances have been eliminated in consolidation.
Prior
to the completion of the IPO on December 21, 2011the Company was a wholly owned subsidiary of Inergy. The consolidated financial statements that are presented for the periods prior to the IPO have been prepared to represent the net assets and related historical results of the Company as if it were a stand-alone entity with the exception that the operations of Tres Palacios Gas Storage LLC (which was assigned to Inergy on November 25, 2011) has been excluded from the historical results. The general ledger of each entity owned by the Company (excluding Tres Palacios Gas Storage LLC) forms the primary basis for the
accompanying financial statements. Costs incurred by Inergy which benefit both the Company and Inergy's wholly owned subsidiaries have been allocated in a manner described in “Allocation of Expenses” below.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.
Reclassifications
The
consolidated statement of operations for the three months ended December 31, 2011 reflects a $0.9 million reclassification between firm storage revenue and hub services revenue. The consolidated balance sheet at September 30, 2012 reflects $2.6 million bank overdraft reclassification to accrued expenses. These reclassifications had no effect on net income.
Note 2 – Summary of Significant Accounting Policies
Revenue
Recognition
Revenue for natural gas and NGL firm storage is recognized ratably over the contract period regardless of the volume of natural gas or NGL stored by the Company's customers. Revenue from natural gas firm storage is affected to a lesser extent by volumes of stored gas received and or delivered by the Company's customers. Revenue for transportation services is recognized ratably over the contract period. Transportation revenue is derived from the sale of capacity that the
Company has secured on certain third party pipelines, revenues for transportation on the East Pipeline and transportation revenue from placing the North-South Facilities and the MARC I Pipeline into service in the 2012 and 2013 fiscal years, respectively. Revenue from transportation services is also affected to a lesser extent by volumes of gas transported during the period. Revenue from hub services is recognized ratably over the contract period. The contract period for hub services is typically less than one year. Revenues from the sale of salt are recognized when product is shipped to the customer or when certain contractual performance requirements have otherwise been met. Revenues from the COLT Hub are recognized when the contractual services are provided, such as loading of
customer rail cars.
Expense Classification
Storage related costs consist of the direct costs to operate the storage and transportation facilities, including power, contractor and fuel costs. These costs support the revenue generated from firm storage, hub services and transportation services due to the intertwined nature of our assets. The Company's transportation related costs consist primarily of costs to procure firm transportation capacity on certain pipelines. Transportation related costs also consist of direct costs to operate the East Pipeline and the MARC I Pipeline. In limited instances, the Company may
sell inventory obtained from fuel-in-kind collections. The cost basis of this inventory will be recorded in storage related costs. Operating and administrative expenses consist of all expenses incurred by the Company other than those described above in storage and transportation related costs and depreciation and amortization. Certain operating and administrative expenses and depreciation and amortization are incurred in providing storage services, but are not included in storage and transportation related costs. These amounts were $12.6 million and $10.4 million for the three months ended December 31, 2012 and 2011,
respectively.
Inherent in the Company's contractual portfolio are certain credit risks. Credit risk is the risk of loss from nonperformance by suppliers, customers or
financial counterparties to a contract. Inergy takes an active role in managing credit risk and has established control procedures, which are reviewed on an ongoing basis. The Company attempts to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate.
One customer, ConEdison, accounted for approximately 14% of the Company's
total revenue for each of the three months ended December 31, 2012 and 2011. No other customer accounted for 10% or more of the Company's total revenue in those periods. All ConEdison revenues are captured in the storage and transportation segment.
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results could differ from those estimates.
Inventories
Inventories
for storage and transportation operations, consisting primarily of natural gas, are stated at the lower of cost or market and are computed predominantly using the average cost method. Inventories for salt operations are stated at the lower of cost or market, cost being principally determined on the first-in, first-out method. All costs associated with the production of finished goods at the salt production facility are captured as inventory costs.
Property, Plant and Equipment
Property, plant and equipment are stated at historical cost less accumulated depreciation. The Company capitalizes all construction related direct labor and material costs as well as the cost of funds used during construction. Amounts
capitalized for cost of funds used during construction amounted to $1.3 million and $1.8 million during the three months ended December 31, 2012, and 2011, respectively. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:
Years
Buildings and improvements
15-25
Office
furniture and equipment
3-7
Vehicles
3-5
Pipelines
15
Base gas
10
Plant equipment
3-20
Salt
deposits are depleted on a unit of production method. Maintenance and repairs are charged to expense as incurred.
The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such events or changes in circumstances are present, a loss is recognized if the carrying value of the asset is in excess of the sum of the undiscounted cash flows expected to result from the use of the asset and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset
exceeds the fair value of the asset. The Company has not identified any indicators that suggest the carrying amount of an asset may not be recoverable for the period ended December 31, 2012.
Identifiable Intangible Assets
Intangible assets acquired in the acquisition of a business are required
to be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer's intent to do so. Deferred financing costs represent financing costs incurred in obtaining financing and are being amortized over the term of the related debt.
The Company has recorded certain identifiable intangible assets, which are amortized on a straight-line basis over their estimated economic lives, as follows:
Years
Customer
accounts
15-20
Covenants not to compete
3-5
Deferred financing costs
5-8
Goodwill
Goodwill is recognized for various acquisitions by the Company as the excess of the cost of the acquisitions over the fair value of the related net assets at the date of acquisition. Goodwill is subject to at least an annual assessment for impairment by applying
a fair-value-based test.
The Company completed its annual impairment test for each of its reporting units and determined that no impairment existed as of September 30, 2012. No indicators of impairment were identified requiring an interim impairment test during the three-month period ended December 31, 2012.
Income Taxes
The
Company and its majority unitholder, Inergy, are generally not subject to federal or state income tax. Therefore, the earnings of the Company are included in the federal and state income tax returns of its common unitholders and, as a result of Inergy's majority ownership interest in the Company, the limited partners of Inergy. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Company's partnership agreement.
Cash
and Cash Equivalents
The Company defines cash equivalents as all highly liquid investments with maturities of three months or less when purchased.
Income Per Unit
The Company calculates basic net income per limited partner unit by utilizing the two class method. Net income available to partners and the weighted-average number of units outstanding are presented only for the period subsequent to the IPO on December 21, 2011. Earnings (net income available to partners) of US Salt
is presented only for the period subsequent to the acquisition on May 14, 2012. Basic and diluted net income per unit are the same, as there are no potentially dilutive units outstanding at December 31, 2012.
The
carrying amounts of cash, accounts receivable and accounts payable approximate their fair value. As of December 31, 2012, the estimated fair value of the Company's fixed-rate senior notes, based on available trading information, totaled $515.3 million compared with the aggregate principal amount at maturity of $500.0 million. The fair value of debt was determined based on market quotes from Bloomberg. At December 31, 2012, the Company's $600.0 million revolving credit
facility had amounts outstanding of $179.8 million, which approximated fair value due primarily to the floating interest rate associated with borrowings under the credit facility.
Transactions with Inergy
Inergy has historically provided the Company with funding to support its acquisition, capital expansion and working capital needs. The amounts provided by Inergy to finance acquisitions were considered to be permanent investments by Inergy and have accordingly been classified as parent company's investment on the consolidated financial statements of the Company. Amounts
financed to support capital expansion and working capital needs, net of what the Company provided to Inergy were considered to be loans and were classified as payable to Inergy on the Company's consolidated financial statements. In connection with the Company's IPO on December 21, 2011, Inergy extinguished $152.8 million of indebtedness owed by the Company, which was treated as a capital contribution by Inergy.
Subsequent to the IPO, the
Company used its revolving credit facility to finance acquisitions and its capital expansion and working capital needs.
Interest on intercompany loans provided by Inergy was historically charged on the loan balances during the period of construction of the Company's expansion projects.
Allocation of Expenses
The Company shares common management, operating and administrative and overhead costs with Inergy. The shared costs allocated to the Company
totaled $4.2 million (including $2.2 million of unit-based compensation charges) and $2.5 million (including $0.9 million of unit-based compensation charges) for the three months ended December 31, 2012 and 2011, respectively. In conjunction with its IPO, the Company entered into an Omnibus Agreement with Inergy that requires the Company to reimburse Inergy for all shared costs
incurred on its behalf. Due to the nature of these shared costs, it is not practicable to estimate what the costs would have been on a stand-alone basis. Accordingly, the accompanying financial statements may not necessarily be indicative of the conditions that would have existed, or the results of operations that would have occurred, if the Company had operated as a stand-alone entity.
Comprehensive Income (Loss)
Comprehensive income includes net income and other comprehensive income. Other comprehensive income includes the realized loss on a derivative instrument that the Company entered into to hedge the purchase
of base gas for one storage facility. The amount included in other comprehensive income associated with this derivative is being reclassified to earnings over the same period that the hedged base gas is recorded in earnings. The amount reclassified to earnings for the three-month period ended December 31, 2012 was not material.
Property Tax Receivable
The Company receives property tax benefits under New York's Empire State Development program. The amounts due to be refunded to the
Company under this program amounted to $4.8 million and $5.7 million as of December 31, 2012 and September 30, 2012, respectively. At December 31, 2012, $2.0 million of the amounts due to be refunded were classified in prepaid expenses and other current assets, and $2.8 million were classified in other long-term assets on the consolidated balance sheets. At September 30, 2012, $2.0
million of the amounts due to be refunded were classified in prepaid expenses and other current assets, and $3.7 million were classified in other long-term assets on the consolidated balance sheets.
The
Company prepays property taxes in certain taxing jurisdictions and thus records the amount of taxes relating to future periods in prepaid expenses and other current assets, which totaled $1.2 million and $1.7 million at December 31, 2012 and September 30, 2012, respectively.
Property, Plant and Equipment Accrual
The Company has accrued for property, plant and equipment, including certain construction work in process
relating to construction efforts on various growth projects. At December 31, 2012the Company had accrued $28.4 million relating to property, plant and equipment, of which $27.3 million was classified as accrued expenses and $1.1 million was classified as accounts payable on the consolidated balance sheets. At September 30, 2012the Company had accrued $45.1 million relating to property, plant and equipment, of which $44.1
million was classified as accrued expenses and $1.0 million was classified as accounts payable on the consolidated balance sheets.
Asset Retirement Obligations
An asset retirement obligation ("ARO") is an estimated liability for the cost to retire a tangible asset. The fair value of these AROs could not be made as settlement dates (or range of dates) associated with these assets were not estimable.
Accounting for Unit-Based Compensation
The Company
has a unit-based employee compensation plan and all share-based payments to employees, including grants of employee stock options, are recognized in the income statement based on their fair values. The amount of compensation expense recorded by the company during the three months ended December 31, 2012 was $2.6 million ($2.2 million allocated by Inergy for Inergy units and $0.4 million for Inergy Midstream units). The amount of compensation expense allocated to the Company during the three
months ended December 31, 2011 was $0.9 million.
Segment Information
There are certain accounting requirements that establish standards for reporting information about operating segments, as well as related disclosures about products and services, geographic areas and major customers. Further, they define operating segments as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. In determining its operating segments, the
Company examined the way it organizes its business internally for making operating decisions and assessing business performance. See Note 9 for disclosures related to the Company's three operating and reporting segments.
On December 7, 2012, the
Company completed the acquisition of 100% of the ownership interest of Rangeland Energy, LLC in exchange for $425 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments. Rangeland Energy, LLC was the owner and operator of the COLT Hub. Concurrently with the closing of the acquisition, the Company completed the private placement of $225 million common units and $500 million in senior unsecured notes due 2020. The remaining net proceeds from these offerings were used to repay borrowings under the Credit Facility.
The primary purpose of this acquisition was to acquire the integrated crude oil loading terminal,
storage, and pipeline assets of Rangeland Energy, LLC and its subsidiaries, which are located in Williams County, North Dakota. The COLT Hub primarily consists of 720,000 barrels of crude oil storage, two 8,700-foot rail loops, an eight-bay truck unloading rack, and a 21-mile bi-directional crude oil pipeline that connects the hub to gathering systems and interstate crude oil pipelines.
The
above table reflects the preliminary purchase price allocation related to the acquired assets and liabilities, which is reflected in these financial statements. During the nine months ended September 30, 2013 the purchase price allocation was finalized, and the amounts included in that final purchase price allocation were materially consistent with the amounts presented above. The $165.0 million of goodwill has been assigned to the crude segment. Goodwill recognized in the transaction relates primarily to expanding our geographic footprint into a new growing shale play. The name of the acquired entity has since been changed from Rangeland Energy, LLC to Inergy Crude Logistics, LLC ("ICL"). Based on the purchase price allocation, amortization expenses relative to the intangible assets acquired are expected to be $26.6 million,
$29.2 million, $27.4 million, $19.3 million, and $10.7 million for the years ended December 31, 2013 through December 31, 2017, respectively.
The following represents the pro forma consolidated statements of operations as if the COLT Hub had been included in the consolidated results of the Company for the entire three-month periods ended December 31, 2012 and 2011
(in millions):
(Unaudited) Pro Forma Consolidated Statement of Operations
These amounts have been calculated after applying the Company's accounting policies and adjusting the results of Rangeland Energy, LLC to reflect the depreciation and amortization that would have been charged assuming the preliminary fair value adjustments to property, plant and equipment and intangible
assets had been made at the beginning of the current period. The entities acquired were development stage entities (as defined by ASC Topic 915, Development Stage Entities) until commencing principal commercial operations in June 2012.
On December 21, 2011, the Company entered into a new $500.0 million revolving credit facility (“Credit Facility”). The Credit Facility, which matures in December 2016, is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The Credit Facility has an accordion feature that allows the Company to increase loan commitments by up to $250.0 million, subject to the lenders' agreement and the satisfaction of certain conditions. The Credit Facility
includes a $10 million sub-limit for same-day swing line advances, and a $100 million sub-limit for letters of credit.
On April 16, 2012, the Company exercised a portion of its accordion feature under the Credit Facility and increased the loan commitments thereunder by $100.0 million and as a result, the accordion feature available to the Company is now $150 million. The aggregate amount of revolving loan commitments under the Credit Facility is now $600
million, and can be increased by up to $150 million, subject to the lenders' agreement and the satisfaction of certain conditions.
On November 16, 2012, the Company amended its revolving credit facility to, among other things, (i) amend the definition of consolidated EBITDA to include projected consolidated EBITDA attributable to fixed fee contracts acquired in the acquisition of the COLT Hub; (ii) increase the maximum total leverage ratio to 5.50 to 1.0 for any two consecutive fiscal quarters ending on or immediately after the date of
the consummation of a permitted acquisition in excess of $50 million; and (iii) add a senior secured leverage ratio of 3.75 to 1.0 on and after the cumulative issuance of $200 million or more of permitted junior debt.
The Company's outstanding balance on the Credit Facility amounted to $179.8 million and $416.5 million at December 31, 2012 and September 30, 2012, respectively. Outstanding
standby letters of credit under the Credit Facility amounted to $2.0 million at December 31, 2012. As a result, the Company had approximately $418.2 million of remaining capacity at December 31, 2012, subject to compliance with any applicable covenants under such facility.
The Credit Facility contains various covenants and restrictive provisions that limit its ability to, among other things:
•
incur
additional debt;
•
make distributions on or redeem or repurchase units;
•
make certain investments and acquisitions;
•
incur or permit certain liens
to exist;
•
enter into certain types of transactions with affiliates;
•
merge, consolidate or amalgamate with another company; and
•
transfer or otherwise
dispose of assets.
If the Company fails to perform its obligations under these and other covenants, the lenders' credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the Credit Facility could be declared immediately due and payable. The Credit Facility also has cross default provisions that apply to any other material indebtedness of the Company.
Borrowings under the Credit Facility are generally secured by pledges of the equity interests in the Company's wholly
owned subsidiaries, liens on substantially all of the Company's real and personal property, and guarantees issued by all of the Company's subsidiaries. Borrowings under the Credit Facility, other than swing line loans, will bear interest at its option at either:
•
the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%;
(ii) JP Morgan's prime rate; or (iii) the Adjusted LIBO Rate plus 1%; plus a margin varying from 0.75% to 1.75% depending on the Company's most recent total leverage ratio; or
the
Adjusted LIBO Rate, which is defined as the LIBO Rate plus a margin varying from 1.75% to 2.75% depending on the Company's most recent total leverage ratio.
Swing line loans bear interest at the Alternate Base Rate plus a margin varying from 0.75% to 1.75%. The unused portion of the Credit Facility is subject to a commitment fee ranging from 0.30% to 0.50% per annum according to its most recent total leverage ratio. Interest on Alternative Base Rate loans is payable quarterly or, if the Adjusted
LIBO Rate applies, it may be paid at more frequent intervals.
The Credit Facility requires the Company to maintain a consolidated leverage ratio (as defined in its credit agreement) of not more than 5.00 to 1.0 (subject to increase to 5.50 to 1.0 following certain permitted acquisitions, as indicated above) and an interest coverage ratio (as defined in its credit agreement) of not less than 2.50 to 1.0. The Credit Facility also requires maintenance of a senior secured leverage ratio (as defined in its credit agreement) of not more than 3.75 to 1.0 on and after the cumulative issuance of $200
million or more of permitted junior debt.
Senior Notes
On December 7, 2012, the Company and NRGM Finance Corp. (“Finance Corp.” and together with the Company, the “Issuers”) issued and sold $500 million in a private offering in aggregate principal amount of their 6.0% Senior Notes due 2020 (the “Notes”) pursuant to a purchase agreement dated November 29, 2012. The Issuers issued
the Notes pursuant to an indenture dated as of December 7, 2012 (the “Indenture”), among the Issuers, the subsidiary guarantors and U.S. Bank National Association, as trustee. The Notes will mature on December 15, 2020. Interest on the Notes is payable semi-annually in arrears on June 15 and December 15 of each year, beginning on June 15, 2013. The Notes are guaranteed on a senior unsecured basis by the Company and all of the
Company's existing subsidiaries (other than Finance Corp.) and certain of the Company's future subsidiaries. The guarantees are full and unconditional, and all of the guarantees are joint and several. Inergy Midstream, L.P. has no independent assets or operations and NRGM Finance Corp. is a 100% finance subsidiary of the Company.
The Indenture restricts the
Company's ability and the ability of its subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company's units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company's restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the
Company's assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries and (x) enter into sale and leaseback transactions. These covenants are subject to a number of important exceptions and qualifications. At any time when the Notes are rated investment grade by either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default or Event of Default (each as defined in the Indenture) has occurred and is continuing, many of these covenants will terminate.
Inergy and its wholly owned subsidiaries do not provide credit support or guarantee any amounts
outstanding under the Credit Facility or Notes.
Note 6 - Partners’ Capital
Common Units
On December 7, 2012, the Company sold 10,714,283 newly issued common units at $21.00 per unit for a total purchase price of approximately $225 million pursuant to a Common Unit Purchase Agreement, dated November
3, 2012 (the “Common Unit Purchase Agreement”), between the the Company and the purchasers named therein. The issuance of the common units pursuant to the Common Unit Purchase Agreement was made in reliance upon an exemption from the registration requirements of the Securities Act, pursuant to Section 4(2) thereof. The Company filed a copy of the Common Unit Purchase Agreement as Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on November 5, 2012.
The Company has three classes of unitholders which include a general partner, limited partners and IDR holders. The Company's partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December
31, 2011, the Company will distribute all available cash (as defined in the Company's partnership agreement) to common unitholders of record on the applicable record date. The general partner will not be entitled to distributions on its non-economic general partner interest. The IDRs are entitled to receive 50% of the cash distributed from operating surplus (as defined in the Company's partnership agreement) in excess of the initial quarterly distribution of $0.37.
Inergy, as the initial holder of the
Company's IDRs, has the right under its partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial quarterly distribution and to reset, at a higher level, the quarterly distribution amount (upon which the incentive distribution payments to Inergy would be set). If Inergy elects to reset the quarterly distribution, it will be entitled to receive a number of newly issued Company common units. The number of common units to be issued to Inergy will equal the number of common units that would have entitled the holder to the quarterly cash distribution in the prior quarter equal to the distribution to Inergy on the IDRs in such prior quarter. As the reset election has not been made, no additional units have been issued. For accounting purposes, diluted earnings per unit can be impacted, (even if the reset election has not been made), if the combined impact of issuing the additional units and resetting the cash
target distribution is dilutive. Currently, diluted earnings per unit has not been impacted because the combined impact is antidilutive.
Quarterly Distributions of Available Cash
A summary of the Company’s limited partner quarterly distribution for the three months ended December 31, 2012 is presented below:
On January 25, 2013, the Company declared a distribution of $0.39 per limited partner unit to be paid on February 14, 2013, to unitholders of record on February 7,
2013 with respect to the first fiscal quarter of 2013. On February 14, 2012, the Company paid a pro-rated distribution of $0.04 per limited partner unit to unitholders of record on February 7, 2012 with respect to the first fiscal quarter of 2012. The $0.04 cash distribution per limited partner unit corresponded to an initial quarterly cash distribution of $0.370 per quarter ($1.48 annually)
and represented the pro-rated distribution for the period of time from December 21, 2011, the closing of the Company's IPO, through December 31, 2011, the end of the first fiscal quarter of 2012.
Note 7 - Commitments and Contingencies
The Company has entered into certain purchase commitments in connection with the identified growth projects primarily related to the Watkins Glen NGL development project, the
MARC I Pipeline, and certain upgrades to the US Salt facility. The Watkins Glen NGL development project entails the conversion of certain caverns created by US Salt into 2.1 million barrels of NGL storage. The MARC I Pipeline, which was placed into service in December 2012, is a 39 mile, 30 inch bi-directional pipeline that extends between the Company's Stagecoach south lateral interconnect with Tennessee Gas Pipeline Company's 300 Line near its compressor station 319 and Transco's Leidy Line near its compressor station 517, and is capable of providing 550 MMcf/d of firm transportation capacity. At December 31, 2012,
the total of these firm purchase commitments was $7.9 million and the purchases associated with these commitments are expected to occur over the next twelve months.
The Company is periodically involved in litigation proceedings. The results of litigation proceedings cannot be predicted with certainty; however, management believes that the Company does not have material potential liability in connection with these proceedings that would have a significant financial impact on its consolidated financial condition, results of operations or cash flows.
In June 2010, the Company and CNYOG entered into a letter of intent with Anadarko Petroleum Corporation (“Anadarko”) which contemplated that, subject to certain conditions, Anadarko may exercise an option to acquire up to a 25% ownership interest in the MARC I pipeline. On September 23, 2011, Anadarko filed a complaint against the Company and CNYOG in the Court of Common Pleas
in Lycoming County, Pennsylvania (Cause No. 11-01697) alleging that (i) Anadarko had an option to acquire, and timely exercised its option to acquire, a 25% ownership interest in the MARC I pipeline, (ii) the Company refused to enter into definitive agreements under which Anadarko would acquire a 25% interest in the pipeline and, by doing so, the Company breached the letter of intent, and (iii) by refusing to enter into definitive agreements, the Company breached a duty of good faith and fair dealing in connection with the letter of intent. Based on these allegations, Anadarko seeks various remedies, including specific
performance of the letter of intent and monetary damages. Inergy may be required to indemnify the Company for litigation related costs and damages under the omnibus agreement that governs the Company's relationship with Inergy.
The Company filed its answer to Anadarko's complaint on January 17, 2012 and discovery is ongoing. The Company believes that Anadarko's claims are without merit and intends to vigorously defend themselves in the lawsuit.
The
Company utilizes third-party insurance subject to varying retention levels of self-insurance, which management considers prudent.
Note 8 - Related Party Transactions
The Company has recorded sales to Inergy of $3.4 million and $2.0 million for the three months ended December 31, 2012 and 2011,
respectively. The sales relate to storage space leased at the Company's Bath storage facility. These sales increased the Company's net income by $2.4 million and $1.1 million for the three months ended December 31, 2012 and 2011, respectively.
At December 31, 2012, the
Company had a $1.2 million receivable from Inergy that is included in prepaid expenses and other current assets on the consolidated balance sheet. At September 30, 2012, the Company had a $0.3 million payable to Inergy that is included in accrued expenses on the consolidated balance sheet.
As discussed in Note 2, prior to the Company's IPO, Inergy funded certain of the Company's activities.
Note
9 - Segments
Effective with the acquisition of the COLT Hub, the Company's financial statements reflect three operating and reporting segments: (i) storage and transportation operations, (ii) salt operations and (iii) crude operations. The Company's storage and transportation operations include storage and transportation of natural gas and NGLs for third parties. The Company's salt operations include the production and sale of salt products. The Company's crude operations include the storage, loading and transportation of crude oil
for third parties.
The identifiable assets associated with each reporting segment include accounts receivable and inventories. Revenues, gross profit, identifiable assets, goodwill, property, plant and equipment, total assets and expenditures for property, plant and equipment for each of the
Company's reporting segments are presented below (in millions):
remedies, including specific performance of the letter of intent and monetary damages.
On September 9, 2013, the Company and Anadarko entered into a confidential settlement agreement to resolve any and all
claims relating to the litigation. CEQP has reimbursed the Company for the amount paid to Anadarko under the settlement
agreement
pursuant to the omnibus agreement that governs the Company’s relationship with CEQP.
Crestwood Merger
On October 7, 2013, the Company completed the Crestwood Merger and the merger of Legacy CMLP with and into Inergy Midstream, with Inergy Midstream continuing as the surviving entity and immediately thereafter changing its name to “Crestwood Midstream Partners LP” and changing its NYSE listing symbol to “CMLP.”The Company also changed its principal executive offices
to 700 Louisiana Street, Suite 2060, Houston, Texas77002.
In addition, following the closing of the Crestwood Merger on October 7, 2013, (i) the Company and Crestwood Midstream Finance Corp. (formerly known as NRGM Finance Corp., “Finance Corp.”) assumed the obligations of Legacy CMLP and Crestwood Midstream Finance Corporation under their $350 million in aggregate principal amount of 7.75%
senior unsecured notes due April 2019; (ii) certain Legacy CMLP subsidiary guarantors of the 7.75% senior notes due April 2019 guaranteed the obligations of the Company and Finance Corp. under the Notes; (iii) the Company’s subsidiary guarantors of the Notes guaranteed obligations of Legacy CMLP and Crestwood Midstream Finance Corporation under the 7.75% senior notes due April 2019; and (iv) Crestwood Midstream Finance Corporation merged with and into Finance Corp., with Finance Corp. continuing as the surviving entity, and Finance Corp. immediately thereafter changed its name to “Crestwood Midstream Finance Corp.”
More
detailed descriptions of the foregoing events are contained in the Form 8-K filed by the Company with the Securities and Exchange Commission on October 10, 2013 (the "Merger Form 8-K").
The following represents the pro forma consolidated statements of operations as if the Crestwood Merger occurred on October 1, 2011, and thus had been included in the consolidated results of the Company for the three-month periods ended December 31, 2012 and 2011, respectively (in millions, except
per unit data):
(a) Amounts
reflect the pro forma adjustments for the COLT Hub, which was acquired by the Company on December 7, 2012. See Note 4 for additional information regarding the COLT Hub acquisition.
These amounts have been calculated after applying the Company's accounting policies.
New Secured Revolving Credit Facility
Immediately following the Crestwood Merger, on October 7, 2013, the
Company entered into a new five-year senior secured credit facility under which at least $1 billion of cash borrowing capacity will be made available to the Company and its subsidiaries by a syndicate of financial institutions. The Company borrowed $623.6 million of funds under the new revolving credit facility to repay in full and retire the NRGM Credit Facility, Legacy CMLP's $550 million revolving credit facility, and
Crestwood Marcellus Midstream LLC's $200 million revolving credit facility. Subject to limited exception, the new credit facility is secured by substantially all of the equity interests and assets of the Company's restricted domestic subsidiaries, and is joint and severally guaranteed by substantially all of the Company's restricted domestic
subsidiaries. A more detailed description of the new revolving credit facility is contained in the Merger Form 8-K.
Arrow Midstream Holdings, LLC Acquisition
On October 8, 2013, the Company and its wholly-owned subsidiary, Crestwood Arrow Acquisition LLC ("Crestwood Arrow"), entered into an agreement to acquire Arrow Midstream Holdings, LLC ("Arrow"), a privately-held midstream company, for approximately $750 million, subject to customary capital expenditure and working capital adjustments. Under
the merger agreement, Crestwood Arrow will merge with and into Arrow (the “Arrow Acquisition”), with Arrow continuing as the surviving entity and a wholly-owned subsidiary of the Company. The base merger consideration consists of $550 million in cash and 8,826,125 common units of the Company to be issued to the sellers, subject to adjustment. The transaction is expected to close on November 8, 2013.
Arrow, through its wholly-owned subsidiaries, owns and operates
substantial crude oil, natural gas and water gathering systems located on the Fort Berthold Indian Reservation in the core of the Bakken Shale in McKenzie and Dunn Counties, North Dakota. The system today consists of over 460 miles of gathering pipeline including 150 miles of crude oil gathering pipeline, 160 miles of natural gas gathering pipeline, and 150 miles of water gathering lines. Current volumes on the system are approximately 50,000 barrels per day of crude oil, 15 million cubic feet per day of rich natural gas and 8,500 Bbls/d of water. Additionally, the acquired assets include salt water disposal wells and a 23-acre
central delivery point with multiple pipeline take-away outlets and a fully-automated truck loading facility.
More detailed information about the Arrow Acquisition is contained in the Form 8-K filed by the Company with the Commission on October 15, 2013.
The Company’s valuation of the assets and liabilities assumed has not been completed as the acquisition has not closed to date. The Company expects the significant components of the valuation to include property, plant and equipment,
intangible contract assets and goodwill.
Equity Offering
On October 7, 2013, the Company sold 773,191 common units at $21.69 per unit pursuant to an underwriters’ option to purchase additional common units, as such option was granted to the underwriters by the Company in its September 2013 equity offering. The sale generated approximately $16.8
million of net proceeds after deducting underwriters’ discounts, commission and other offering expenses. Proceeds were used to repay borrowings under our new five-year $1 billion senior secured revolving credit facility.
On October 23, 2013, the Company sold 14,000,000 common units to underwriters at $21.19 per unit in a registered public offering generating net proceeds of approximately $296.4 million after deducting underwriters’ discounts, commission and other offering expenses. Proceeds will be used to pay a portion of the base
merger consideration to the sellers in the Arrow Acquisition and to pay related fees and expenses. On October 30, 2013, the Company sold 2,100,000 common units at $21.19 per unit pursuant to an underwriters' option to purchase additional common units, as such option was granted to the underwriters by the Company in its October 23, 2013 equity offering.
Senior Notes Offering
On October
22, 2013, Crestwood Midstream Partners LP and Crestwood Midstream Finance Corp. announced an offering of $600 million in aggregate principal amount of 6.125% senior notes due 2022 in a private offering exempt from the registration requirements of the Securities Act of 1933. The notes will be guaranteed on a senior unsecured basis by substantially all of the Company’s existing and future domestic restricted subsidiaries (other than Finance Corp.), subject to certain exceptions. The Company expects to close the private placement on November 8, 2013. The
Company anticipates using the net offering proceeds to fund a portion of the consideration payable in the Arrow Acquisition and to pay related fees and expenses, and to repay borrowings under the Company’s new $1 billion senior secured revolving credit facility.
Management’s
Discussion and Analysis of Financial Condition and Results of Operations
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” should be read in conjunction with the accompanying consolidated financial statements.
The statements in this Quarterly Report on Form 10-Q that are not historical facts, including most importantly, those statements preceded by, or that include the words “believe,”“expect,”“may,”“will,”“should,”“could,”“anticipate,”“estimate,”“intend” or the negation thereof, or similar expressions, constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 (“Reform Act”). Such forward-looking
statements include, but are not limited to, our belief that we will complete our growth projects; our belief that we will have the capacity to fund internal growth projects and acquisitions; our belief that we will be able to generate stable cash flows; and our belief that Anadarko’s litigation claims are without merit. Such forward-looking statements involve risks, uncertainties and other factors which may cause the actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors include, but are not limited to, the following: changes in general and local economic conditions; competitive conditions within our industry, including crude oil and natural gas production levels and prices; our ability to complete internal growth projects on time and on budget; the price and availability of debt and equity financing; the effects of existing and future
governmental legislation and regulations; and natural disasters, weather-related delays, casualty losses and other matters beyond our control. We will not undertake and specifically decline any obligation to publicly release the result of any revisions to any forward-looking statements to reflect events or circumstances after the date of such statements or to reflect events or circumstances after anticipated or unanticipated events.
The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this transition report on Form10-Q and our Annual Report on Form 10-K for the fiscal year
ended September 30, 2012. This transition report on Form 10-Q is being filed due to our change in year end, and covers the transition period that began October 1, 2012 and ended December 31, 2012. The comparative three month period ended December 31, 2011 has also been presented.
Overview
We are a predominantly fee-based, growth-oriented limited partnership that develops, acquires, owns and operates midstream energy assets. We own and operate natural gas and NGL storage and transportation facilities, a salt production business located in the Northeast region of the United States, and a crude
oil loading and storage terminal in North Dakota. We own and operate four natural gas storage facilities that have an aggregate working gas storage capacity of approximately 41.0 Bcf; natural gas pipeline facilities with 905 MMcf/d of transportation capacity; a 1.5 million barrel NGL storage facility; US Salt, a leading solution mining and salt production company; and the COLT Hub, a crude oil distribution hub located in North Dakota.
Our primary business objective is to increase the cash distributions that we pay to our unitholders by growing our business through the development, acquisition and operation of additional midstream assets near production and demand centers. An integral part of our growth strategy is the continued development of our platform of interconnected natural gas assets in the Northeast that can be operated as an integrated storage and transportation
hub. For example, because we believe storage and transportation customers value operating flexibility, we expect to increase the interconnectivity between our natural gas assets and third-party pipelines, thereby resulting in increased demand for our services. We also expect our growth strategy to reflect our desire to diversify our operations, in terms of both our geographic footprint and the type of midstream services we provide to customers. Our recent acquisition of the COLT Hub is consistent with these objectives.
Organic growth projects, including both expansions and greenfield development projects, have recently provided cost-effective options for us to grow our midstream infrastructure base. In general, purchasers of midstream infrastructure have paid relatively high prices (measured in terms of a multiple of EBITDA or another financial metric) to acquire midstream
assets and operations in recent arms-length transactions. Although the prices paid for certain types of midstream assets are likely to remain robust for the foreseeable future, acquisitions will continue to permit us to gain access to new markets (with respect to geographic footprint and product offerings) and develop the scale required to grow our business quickly and successfully. We therefore expect to grow our business in the near term through both organic growth projects and acquisitions.
Our operations include (i) the storage and transportation of natural gas and NGLs, which are reported in our storage and transportation reporting segment, (ii) US Salt's production and wholesale distribution of evaporated salt products, which are reported in our salt reporting segment, and (iii) the COLT Hub operations, which are reported in our crude reporting segment. The cash flows
from our storage and transportation operations are predominantly fee-based under one to ten year contracts with creditworthy counterparties and, therefore, are generally economically stable and not significantly affected in the short term by
changing commodity prices, seasonality or weather fluctuations. The cash flows from our salt operations represent sales to creditworthy customers typically under contracts that are less than one year in duration, and these cash flows tend to be relatively
stable and not subject to seasonal or cyclical variation due to the use of, and demand for salt products in everyday life. The cash flows from our crude operations represent sales to creditworthy customers typically under contracts that are multiple years in duration.
A substantial percentage of our operating cash flows are generated by our natural gas storage operations. Our natural gas storage revenues are driven in large part by competition and demand for our storage capacity and deliverability. Demand for storage in the Northeast is projected to continue to be strong, driven by a shortage in storage capacity and a higher than average annual growth in natural gas demand. This demand growth is primarily driven by the natural gas-fired electric generation sector and conversion from
petroleum-based fuels. Due to the high percentage of our cash flows generated by our natural gas storage operations, we have attempted to diversify our asset base recently by developing natural gas transportation assets and NGL storage assets.
Our ability to market available transportation capacity is impacted by supply and demand for natural gas, competition from other pipelines, natural gas price volatility, the price differential between physical locations on our pipeline systems (basis spreads), economic conditions, and other factors. Our transportation facilities have benefited from, and we expect our pipelines to continue to benefit from, the development of the Marcellus shale as a significant supply basin. As LDCs and other customers increasingly utilize short-haul transportation options to satisfy their transportation needs, we believe the location of our transportation
assets relative to the Marcellus shale will enable us to realize additional benefits.
Our long-term profitability will be influenced primarily by (i) successfully executing our existing development projects and continuing to develop new organic growth projects in our markets; (ii) pursuing strategic acquisitions from third parties, including Inergy, to grow our business; (iii) contracting and re-contracting storage and transportation capacity with our customers; and (iv) managing increasingly difficult regulatory processes, particularly in permitting and approval proceedings at the federal and state levels.
How We Evaluate Our Operations
We evaluate our business performance on the basis of the following
key measures:
•
revenues derived from firm storage contracts and the percentage of physical capacity and / or deliverability sold;
•
revenues derived from transportation contracts and the percentage of physical capacity sold;
•
operating
and administrative expenses; and
•
EBITDA and Adjusted EBITDA.
We do not utilize depreciation, depletion and amortization expense in our key measures because we focus our performance management on cash flow generation and our assets have long useful lives.
A substantial percentage of our revenues are derived from storage services that we provide
under firm contracts. We seek to maximize the portion of our physical capacity sold under firm contracts. With respect to our natural gas storage operations, to the extent that physical capacity that is contracted for firm service is not being fully utilized, we attempt to contract available capacity for interruptible service. The table below sets forth the percentage of operationally available physical capacity or deliverability sold under firm storage contracts, as of December 31, 2012:
Storage
Facility (Commodity)
Percentage
Contractually
Committed
Weighted-Average
Maturity
(Year)
Stagecoach (Natural Gas)
100%
2016
Thomas Corners (Natural Gas)
100%
2015
Seneca
Lake (Natural Gas)
100%
2016
Steuben (Natural Gas)
100%
2017
Bath (NGL)(1)
100%
2016
(1)
We have contracted 100% of our Bath storage facility to an affiliate, Inergy Services.
The North-South Facilities, the MARC I Pipeline, and the East Pipeline provide material earnings to our operations. We will seek to maximize the portion of physical capacity sold on the pipelines under firm contracts. To
the extent the physical capacity that is contracted for firm service is not being fully utilized, we plan to contract available capacity on an interruptible basis. Our existing transportation assets are 89% contracted and committed.
A substantial majority of our revenues from the COLT Hub are derived from multi-year contracts with minimum throughput commitments. We seek to maximize the throughput capacity of the loading facility sold under contracts
with a minimum throughput commitment, and sell the hub's available storage capacity under take-or-pay contracts to the extent storage capacity is not a bundled component of our customer's throughput contracts. As of December 31, 2012, 59% of the COLT Hub's rail loading capacity (or giving effect to contracted throughput increases described below, 89%) was sold under long-term take-or-pay contracts with minimum throughput commitments. A majority of current customer contracts for rail loading capacity increase
through the duration of the contracts to where contractual rail loading commitments approximate the rail loading capacity of the facility.
Operating and Administrative Expenses
Operating and administrative expenses consist primarily of wages, repair and maintenance costs, and professional fees. With the exception of our COLT Hub, these expenses typically do not vary significantly based upon the amount of commodities that we store or transport. Operating and administrative expenses at our COLT Hub are more closely correlated to the quantity of crude oil loaded, stored or transported. We obtain in-kind fuel reimbursements from natural gas shippers in accordance with our FERC gas tariffs and individual
contract terms. The timing of our expenditures may fluctuate with planned maintenance activities that take place during off-peak periods, and changes in regulation also impact our expenditures. In addition, fluctuations in project development costs are impacted by the level of development activity during a period. Our operating and administrative expenses have also increased following our initial public offering due to an increase in legal and accounting costs and related public company regulatory and compliance expenses.
EBITDA and Adjusted EBITDA
We define EBITDA as income before income taxes, plus net interest expense and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA
excluding the gain or loss on the disposal of assets, long-term incentive and equity compensation expense, and transaction costs. Transaction costs are third-party professional fees and other costs that are incurred in conjunction with closing a transaction.
Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:
•
our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or financing
methods;
•
the ability of our assets to generate sufficient cash flow to make distributions to our common unitholders;
•
our ability to incur and service debt and fund capital expenditures; and
•
the viability of acquisitions and other capital expenditure projects and the returns on investment
in various opportunities.
EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure operating performance, liquidity and our ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make distributions to our common unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. EBITDA
and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships in our industry, thereby diminishing such measures' utility.
The following table summarizes the consolidated statement of operations components for the three months ended December 31, 2012 and 2011, respectively (in millions):
Three
Months Ended December 31,
Change
2012
2011
In Dollars
Percentage
Revenues
$
50.4
$
46.8
$
3.6
7.7
%
Service/product
related costs
10.9
11.1
(0.2
)
(1.8
)
Operating and administrative expenses
11.7
6.1
5.6
91.8
Depreciation
and amortization
15.2
12.0
3.2
26.7
Loss on disposal of assets
0.6
—
0.6
*
Operating
income
12.0
17.6
(5.6
)
(31.8
)
Interest expense, net
5.5
—
5.5
*
Net
income
$
6.5
$
17.6
$
(11.1
)
(63.1
)%
*
Not
meaningful
Revenue. Revenues for the three months ended December 31, 2012, were $50.4 million, an increase of $3.6 million, or 7.7%, from $46.8 million during the same three-month period in 2011.
Revenues from firm storage were $23.6 million
for the three months ended December 31, 2012, an increase of $0.7 million, or 3.1%, from $22.9 million during the same three-month period in 2011. NGL firm storage revenues increased $1.3 million due to the changes in the contracts and customer mix at our Bath facility, partially offset by a $0.9 million reduction of firm storage revenues at our Stagecoach storage facility.
Revenues
from transportation were $8.2 million for the three months ended December 31, 2012, an increase of $1.7 million, or 26.2%, from $6.5 million during the same three-month period in 2011. Transportation revenues increased $2.9 million and $2.8 million due to the placement into service of our North-South Facilities and MARC I Pipeline, respectively; and are partially offset by $4.0 million due to changes in the capacity we held on TGP's 300 Line.
Revenues
from hub services were $3.2 million for the three months ended December 31, 2012, a decrease of $1.1 million, or 25.6%, from $4.3 million during the same three-month period in 2011. This decrease is primarily a result of firm wheeling service shippers utilizing their firm capacity in lieu of interruptible capacity, thus reducing the volume of interruptible wheeling services compared to the prior year.
Revenues from
salt were $12.6 million for the three months ended December 31, 2012, a decrease of $0.5 million, or 3.8%, from $13.1 million during the same three-month period in 2011.
Revenues from crude were $2.8 million for the three months ended December 31, 2012. We
acquired the COLT Hub in December 2012 and thus no revenues were generated in the prior period.
Service/Product Related Costs. Service and product related costs, including storage, transportation, salt costs and crude costs, for the three months ended December 31, 2012, were $10.9 million, a decrease of $0.2 million, or 1.8%, from 11.1 million during the same three-month period in 2011.
Storage
related costs were $2.2 million for the three months ended December 31, 2012, an increase of $0.3 million, or 15.8%, from $1.9 million during the same three-month period in 2011. Storage related costs increased $0.7 million due to compression related costs incurred primarily as a result of placing our North-South Facilities into service in December 2011.
Transportation related costs were $1.0
million for the three months ended December 31, 2012, a decrease of $0.7 million, or 41.2%, from $1.7 million during the same three-month period in 2011. Transportation related costs are primarily comprised of fixed costs for leasing transportation capacity on a non-affiliated interconnecting pipe. This decrease was due to the non-renewal of certain TGP transportation capacity held by us.
Salt related costs were $7.4 million for the three months ended December 31, 2012, a decrease of $0.1 million, or 1.3%, from $7.5 million during the same three-month period in 2011.
Crude related costs were $0.3 million for the three months ended December 31,
2012. We acquired the COLT Hub in December 2012 and thus crude related costs were not generated in the prior period.
Our storage related costs consist primarily of direct costs to run the storage facilities, including electricity, contractor and fuel costs. These costs are offset by any fuel-in-kind collections made during the period. Our salt related costs directly relate to the salt operations and the costs associated with this business. Our transportation related costs consist primarily of our costs to procure firm transportation capacity on certain pipelines. Our crude related costs consist primarily of our costs to operate the COLT Hub (namely rail terminal operations).
Operating and Administrative Expenses. Operating and administrative
expenses were $11.7 million for the three months ended December 31, 2012, compared to $6.1 million during the same three-month period in 2011, an increase of $5.6 million, or 91.8%. Operating expenses increased $1.7 million due to an increase in unit based compensation expenses, $2.6 million due to acquisition related expenses associated with the COLT Hub, $1.3 million in increased operating costs due to placing
our North-South Facilities and our MARC I Pipeline into service, and $0.3 million due to an increase in allocated administrative expenses from Inergy.
Depreciation and Amortization. Depreciation and amortization increased to $15.2 million for the three months ended December 31, 2012, from $12.0 million during the same three-month period in 2011. This $3.2 million, or 26.7%, increase is primarily due to placing our Marc I Pipeline and North-South
Facilities into service in December 2012 and December 2011, respectively and our acquisition of the COLT Hub in December 2012, which increased depreciation and amortization by $1.2 million, $0.8 million, and $1.0 million, respectively.
Interest Expense. Interest expense was $5.5 million for the three months ended December 31, 2012. There was no net interest expense for the three months ended December 31, 2011 due to interest which was capitalized to projects during the prior period.
Net Income. Net income
for the three months ended December 31, 2012, was $6.5 million compared to net income of $17.6 million during the same three-month period in 2011. The $11.1 million, or 63.1%, decrease in net income was primarily attributable to increased operating and administrative costs and depreciation and amortization, partially offset by higher revenue.
EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the three
months ended December 31, 2012 and 2011, respectively (in millions):
Long-term
incentive and equity compensation expense
(2.6
)
(0.9
)
Loss on disposal of assets
(0.6
)
—
EBITDA
$
27.2
$
29.6
Long-term
incentive and equity compensation expense
2.6
0.9
Loss on disposal of assets
0.6
—
Transaction costs (a)
2.6
—
Adjusted
EBITDA
$
33.0
$
30.5
(a) Transaction costs are third party professional fees and other costs that are incurred in conjunction with closing a transaction.
EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any
other measure of financial performance calculated in accordance with generally accepted accounting principles as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make the quarterly distribution and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other corporations or partnerships.
Liquidity and Sources of Capital
Cash
Flows and Contractual Obligations
Net operating cash inflows were $22.2 million and $31.9 million for the three-month periods ended December 31, 2012 and 2011, respectively. The $9.7 million decrease in operating cash flows was primarily attributable to the increase in cash interest paid and increased operating expenses as a result of the placement into service of our North-South Facilities and MARC I Pipeline as well as our acquisition of the COLT Hub, partially offset by an increase in gross profit associated
with the aforementioned capital projects and acquisition.
Net investing cash outflows were $467.1 million and $39.4 million for the three-month periods ended December 31, 2012 and 2011, respectively. Net cash outflows were primarily impacted by the acquisition of the COLT Hub in December 2012.
Net financing cash inflows were $444.9 million and $7.6 million for the three-month
periods ended December 31, 2012 and 2011, respectively. The net change was primarily attributable to proceeds from the issuance of our senior unsecured notes in December 2012 to fund the acquisition of the COLT Hub, along with an increase in net borrowings on our Credit Facility. In addition, we had a $255.0 million decrease in principal payments on our promissory note assumed from Inergy, which occurred as part of our IPO, as well as a $95.4 million decrease in distributions to Inergy.
We believe that anticipated cash from operations and borrowing capacity under our Credit Facility will be sufficient to meet our liquidity needs for the foreseeable future. If our
plans or assumptions change or are inaccurate, or we make acquisitions, we may need to raise additional capital. While global financial markets and economic conditions have been disrupted and volatile in the past, the conditions have improved more recently. However, we give no assurance that we can raise additional capital to meet these needs. As of December 31, 2012, we have firm purchase commitments totaling approximately $7.9 million related to certain of these projects. Additional commitments or expenditures, if any, we may make toward any one or more of these projects are at the discretion of the Company. Any discontinuation of the construction of these projects will likely result in less future cash flow and earnings than we have
indicated previously.
See Note 5 for a description of our Credit Facility and Senior Notes.
Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our
operating and acquisition activities were historically funded by Inergy. Interest was not historically charged on the funding of our activities except during periods of construction.
We have a $600 million revolving credit facility subject to the risk of loss associated with movements in interest rates. At December 31, 2012, we had floating rate obligations totaling $179.8 million under the Credit Facility. We may hedge portions of our borrowings under the Credit Facility from time to time. Floating rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. We had no hedging instruments in place at December 31,
2012.
If the floating rate were to fluctuate by 100 basis points from December 2012 levels, our interest expenditures would change by a total of approximately $1.8 million per year.
Commodity Price, Market and Credit Risk
We do not take title to the natural gas, NGLs, or crude oil that we store, transport, or load for our customers and, accordingly, are not exposed to commodity price fluctuations on natural gas, NGLs, or crude oil stored in, transported by or loaded through our facilities. Except for the line pack and base gas we purchase and use in our natural gas storage and transportation
facilities, which we consider to be a long-term asset, and volume and pricing variations related to small volumes of fuel-in-kind natural gas that we are entitled to retain from our customers as compensation for our fuel costs, our current business model is designed to minimize our exposure to fluctuations in commodity prices. As a result, absent other market factors that could adversely impact our operations, changes in the price of natural gas, NGLs or crude oil should not materially impact our operations.
Item 4.
Controls and Procedures
Disclosure
Controls and Procedures
As of December 31, 2012, we carried out an evaluation under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as to the effectiveness, design and operation of our disclosure controls and procedures (as defined in the Securities Exchange Act of 1934, as amended (Exchange Act) Rules 13a-15(e) and 15d-15(e)). This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, does not expect that our disclosure controls and procedures or our internal controls
will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our Chief Executive Officer and Chief Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2012.
Changes in Internal Control Over Financial Reporting
In fiscal 2013, we completed
the acquisition of the COLT Hub. See Note 4 “Business Acquisitions” to the Consolidated Financial Statements included in Item 1 for a discussion of the acquisition and related financial data.
At the time these financial statements were available to be issued we were in the process of evaluating the internal controls and procedures of our COLT Hub acquisition. Further, we were in the process of integrating their operations. Management completed the evaluation of internal controls during the quarter ended September 30, 2013 and no material changes to the process in place for the quarter ended December 31, 2012 were required.
Part I, Item 1. Financial Statements, Note 7 to the Consolidated Financial Statements, of this Form 10-Q is hereby incorporated herein by reference.
Item 1A. Risk Factors
In
addition to the risk factors disclosed in "Item 1A, Risk Factors" in the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2012, we have the following risk factors related to the acquisition of the COLT Hub.
Our profitability depends on the volume of crude oil handled by the COLT Hub.
The COLT Hub is located in the heart of the Bakken shale oil-producing play and generates fee-based revenues under multiyear contracts by providing crude oil storage, transportation and terminal services,
including rail loading and truck loading/unloading services. A material decrease in crude oil production or refining, as a result of depressed commodity prices, natural decline rates attributable to oil reservoirs, a decrease in exploration and development activities or otherwise, could adversely impact our ability to execute or renew contracts with customers and, in turn, result in a decline in the volume of crude oil processed by the COLT Hub. Our profitability could be materially impacted by a decline in the volume of crude oil loaded, stored or transported by the COLT Hub.
Demand for crude oil is dependent upon numerous factors, including price, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological
advances in fuel economy and energy generation devices, all of which could impact demand. Fluctuations in demand for crude oil, such as fluctuations caused by refinery downtime or shutdown, can have a negative effect on our operating results. Reduced demand in the Bakken play can negatively affect the throughput on the COLT Hub. In addition, the crude oil volumes that support the COLT Hub are dependent on the level of product from crude oil wells in the Williston basin (including the Bakken and Three Fork plays). We have no control over the level of drilling or production activity in these plays, the amount of reserves in these plays, or the rate at which production will decline in these plays. Sustained reductions in exploration or production activity in the Bakken, or in the price of Bakken crude oil relative to crude oil from other production basins or plays, could lead to reduced utilization of the COLT Hub.
The COLT Hub faces intense competition.
Competitors of the COLT Hub primarily include crude oil pipelines, independent terminal developers, and other midstream companies of varying sizes, financial resources and experience. Certain competitors have capital resources many times greater than ours and control (or otherwise have access to) greater volumes of crude oil.
Pipelines are generally the lowest-cost method for shipping crude oil, whereas rail can provide a cost-efficient alternative for transporting crude oil over long distances and trucks are typically limited to short-haul movements due to significant cost escalation with distance. Today, inadequate pipeline infrastructure exists to cost-effectively transport Bakken crude oil supplies
to premium demand markets along the East and West coasts. Rail primarily bridges the gap created by this takeaway capacity constraint and, in this regard, rail plays a critical role in the overall transportation solution designed to move these crude oil supplies to market. As additional crude oil pipelines are constructed over time, pipelines may displace rail as the preferred long-haul option for moving Bakken crude oil to premium demand markets. If the crude oil pipelines required to alleviate the existing infrastructure constraints develop sooner than anticipated (in turn displacing the demand for rail takeaway capacity sooner than expected), then the volumes of crude oil transported, stored and loaded through the COLT Hub may decrease. Our profitability could be materially impacted by an earlier-than-forecast decline in the volume of crude oil served by the COLT Hub.
In
addition, there are low barriers to entry with respect to the development, construction and operation of crude oil loading and storage terminals in the Bakken similar to the COLT Hub. These low barriers to entry, together with the lack of pipeline infrastructure necessary to cost-effectively move crude oil volumes to premium demand markets, has resulted in multiple crude oil terminals being constructed or proposed. Accordingly, to the extent competing crude oil rail and storage terminals are constructed and alternate rail options become availability to shippers, the COLT Hub could be adversely affected by increased competition.
A
change in the jurisdictional characterization of the COLT Hub by federal, state or local regulatory agencies could result in increased regulation, which could affect existing costs and rates.
The COLT Hub includes (i) the COLT terminal, which consists primarily of 600,000 barrels of crude oil storage, two 8,700-foot rail loops, an eight-bay truck unloading rack and crude oil gathering system interconnects; (ii) the Dry Fork terminal, which consists primarily of 120,000 barrels of crude oil storage and interconnections with the Enbridge and Tesoro crude oil pipelines, and (iii) the COLT Connector, a 21-mile, 10-inch bidirectional crude oil pipeline that connects the COLT and Dry Fork terminals. Intrastate crude oil pipelines that do not provide interstate service are not subject to regulation by the FERC. However, the distinction between FERC-regulated interstate pipeline transportation
and intrastate pipeline transportation is a fact-based determination. The classification and regulation of the COLT Connector is subject to change based on future determinations by FERC, federal courts, Congress or regulatory commissions, courts or legislatures in North Dakota.
The COLT Connector moves crude oil owned by third parties either from the COLT terminal's storage tanks to the Dry Fork storage tank, or from the Dry Fork storage tank to the COLT terminal's storage tanks. We believe the existing configuration and use of the COLT Hub and the services it provides to third parties satisfy the traditional tests that FERC has used to determine that the COLT crude oil facilities and services are not in interstate commerce. However, we cannot provide assurance that FERC will not in the future, either at the request of other entities or on its own initiative, determine that some or all of our crude oil pipeline facilities
and the services we provide through the COLT Hub are within its jurisdiction, or that such a determination would not adversely affect our results of operations. If some or all of the COLT Hub becomes subject to FERC jurisdiction, and not otherwise exempt from any applicable regulatory requirements, we would be required to file a tariff with FERC and, if our tariff rates were subject to protest, provide a cost justification for the transportation rate subject to protest and provide service to all potential shippers without undue discrimination. In addition, if the services we provide through the COLT Hub regulated by FERC under the Interstate Commerce Act, the COLT Hub services could be subject to a protest and/or complaint before FERC. If FERC were to determine, in response to a complaint, that our rates are unjust and unreasonable, we could be required to pay reparations and refunds dating to two years before the filing of the complaint. Furthermore, if in the future
services offered by the COLT Hub become subject to substantive state regulation, they could be subject to a protest and/or complaint before the North Dakota Public Service Commission.
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
On December 7, 2012, the Company sold 10,714,283 newly issued common units at $21.00 per unit for a total purchase price of approximately $225 million pursuant
to a Common Unit Purchase Agreement, dated November 3, 2012, between the the Company and the purchasers named therein. The issuance of the common units pursuant to the Common Unit Purchase Agreement was made in reliance upon an exemption from the registration requirements of the Securities Act, pursuant to Section 4(2) thereof. The Company filed a copy of the Common Unit Purchase Agreement as Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on November 5, 2012.
Securities
Purchase Agreement dated as of November 3, 2012 between Rangeland Equity Holdings, LLC and Inergy Midstream, L.P. (incorporated by reference to Exhibit 2.1 to Inergy Midstream, L.P.'s Form 8-K filed on November 5, 2012)
3.1
Certificate of Limited Partnership of Inergy Midstream, L.P. (incorporated by reference
to Exhibit 3.4 to Inergy Midstream, L.P.'s Form S-1/A filed on November 21, 2011)
Indenture, dated as of December
7, 2012, by and among Inergy Midstream, L.P., NRGM Finance Corp., the Guarantors party thereto and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Inergy Midstream, L.P.'s Form 8-K filed on December 13, 2012)
Common Unit Purchase Agreement dated as of November 3, 2012 between Inergy Midstream, L.P. and the Purchasers named therein (incorporated by reference to Exhibit 10.1 to Inergy Midstream, L.P.'s Form 8-K filed on November 5, 2012)
10.2
Amendment
No. 1 to Credit Agreement dated November 16, 2012 among Inergy Midstream, L.P. and JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Inergy Midstream, L.P.'s Form 8-K filed on November 16, 2012)
Certification of Chief Executive Officer of Inergy Midstream, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2
Certification
of Chief Financial Officer of Inergy Midstream, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.1
Certification of Chief Executive Officer of Inergy Midstream, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32.2
Certification
of Chief Financial Officer of Inergy Midstream, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as
amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
