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NRGM > SEC Filings for NRGM > Form 10-K on 21-Nov-2012All Recent SEC Filings

Show all filings for INERGY MIDSTREAM, L.P.

Form 10-K for INERGY MIDSTREAM, L.P.


21-Nov-2012

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Forward-Looking Statements

This report, including information included or incorporated by reference in this report, contains forward-looking statements concerning the financial condition, results of operations, plans, objectives, future performance and business of our company and its subsidiaries. These forward-looking statements include:

statements that are not historical in nature, but not limited to, (i) we expect to place the MARC I Pipeline into service on December 1, 2012; (ii) we expect to sell the 100,000 Dth/d of turned-back MARC I Pipeline capacity at or near rates payable by the existing MARC I shippers; (iii) we expect to receive in early calendar 2013 the approvals required to construct and operate our Watkins Glen NGL storage development project; (iv) we expect to complete and place the Seneca Lake expansion capacity into service in calendar 2013; (v) we believe Anadarko's claims relating to the MARC I Pipeline are without merit; and (vi) we anticipate completing our acquisition of Rangeland Energy in calendar 2012; and

statements preceded by, followed by or that contain forward-looking terminology including the words "believe," "expect," "may," "will," "should," "could," "anticipate," "estimate," "intend" or the negation thereof, or similar expressions.

Forward-looking statements are not guarantees of future performance or results. They involve risks, uncertainties and assumptions. Actual results may differ materially from those contemplated by the forward-looking statements due to, among others, the following factors:

our ability to successfully implement our business plan for our assets and operations;

governmental legislation and regulations;

industry factors that influence the supply of, and demand for, natural gas and NGLs;

weather conditions;

industry factors that influence the demand for natural gas storage and transportation capacity in the Northeast;

costs or difficulties related to the integration of our existing businesses and acquisitions may be greater than expected;

economic conditions;

the availability of natural gas and NGLs, and the price of natural gas and NGLs, to consumers compared to the price of alternative and competing fuels;

environmental claims;

interest rates; and

the price and availability of debt and equity financing.

We have described under "Risk Factors" additional factors that could cause actual results to be materially different from those described in the forward-looking statements. Other factors that we have not identified in this report could also have this effect. You are cautioned not to put undue reliance on any forward-looking statement, which speaks only as of the date it was made.

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 and a salt production business located in the Northeast region of the United States. We own and operate four natural gas storage facilities that have an aggregate working gas storage capacity of 41.0 Bcf; natural gas pipeline facilities with 905 MMcf/d of transportation capacity; a 1.5 million barrel NGL storage facility; and US Salt, a leading solution mining and salt production company.

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.


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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, and (ii) US Salt's production and wholesale distribution of evaporated salt products, which are reported in our salt 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 majority 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 pending acquisition of Rangeland Energy also illustrates how we expect to diversify our asset base through acquisitions.

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.

We remain encouraged by our inventory of growth projects, such as the Watkins Glen NGL storage development project and the Commonwealth Pipeline project. These projects illustrate our diversification objectives, our desire to deploy capital prudently, our strong belief in the markets in which we operate, and our goal of integrating our assets when possible. Importantly, we also believe these projects demonstrate our commitment to our customers and their existing and forecast needs. In addition, many of our growth projects provide a basis for incremental growth, such as our ability to potentially expand the MARC I Pipeline through the installation of additional compression.

Although it has become more difficult to obtain the authorizations required to develop or expand natural gas and NGL storage and transportation assets in the Northeast, we remain confident that the incremental time and money required to pursue and complete market-driven facilities in the Northeast will deliver meaningful value to our unitholders. The regulatory environment, combined with the location of our assets relative to both high-demand markets and the Marcellus shale play, effectively provides a significant barrier to entry that other market participants may find difficult to overcome.


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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.

Firm Storage Contracts

A substantial majority of our revenues is derived from storage services 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 September 30, 2012:
                                Percentage     Weighted-Average
                               Contractually       Maturity
Storage Facility (Commodity)     Committed          (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.

Transportation Contracts

The North-South Facilities and East Pipeline, together with the MARC I Pipeline when placed into service, are expected to 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 and our transportation projects under development are 89% contracted and committed.

Operating and Administrative Expenses

Operating and administrative expenses consist primarily of wages, repair and maintenance costs, and professional fees. These expenses typically do not vary significantly based upon the amount of natural gas or NGLs that we store or transport. 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.


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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.

Recent Developments

On November 16, 2012, we entered into Amendment No. 1 (the "Amendment") with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto, which amends our existing credit facility, dated as of December 21, 2011 (the "Credit Facility"). The Amendment, among other things, (i) amends the definition of Consolidated EBITDA to include projected Consolidated EBITDA attributable to fixed fee contracts from our pending acquisition of Rangeland Energy; (ii) increases 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) adds a Senior Secured Leverage Ratio of 3.75 to 1.00 on and after the cumulative issuance of $200 million or more of Permitted Junior Debt.

On November 3, 2012, we entered into an agreement with Rangeland Equity Holdings, LLC to acquire 100% of the membership interests of Rangeland Energy for cash consideration of $425 million, subject to certain performance goals and working capital adjustments. Rangeland Energy owns and operates the COLT Hub, which is an integrated crude oil rail and storage terminal located in the heart of the Bakken and Three Forks shale oil-producing plays. 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 21-mile bi-directional crude oil pipeline that connects the terminal to crude oil gathering systems and crude oil interstate pipelines. The COLT Hub is capable of moving more than 120,000 barrels of crude oil per day by rail. We expect to complete the Rangeland Energy acquisition in calendar 2012.

We anticipate financing approximately $453 million of Rangeland Energy transaction costs and post-closing capital expenditures through a combination of debt and equity offerings. In particular, we (i) entered into an agreement to sell $225 million through a private placement of common units to qualified institutional investors conditioned upon and closing contemporaneously with the closing of the Rangeland acquisition and (ii) we expect to fund our remaining financing requirements through the sale of long-term senior notes or, if applicable, borrowings on an unsecured $225 million credit facility that we have arranged to backstop our financing requirements. We expect to complete these financing transactions prior to or contemporaneously with the closing of the Rangeland Energy acquisition.


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Results of Operations

Fiscal Year Ended September 30, 2012 Compared to Fiscal Year Ended September 30, 2011

The following table summarizes the consolidated statement of operations for the fiscal years ended September 30, 2012 and 2011, respectively (in millions):

                                          Year Ended
                                         September 30,                Change
                                        2012       2011      In Dollars    Percentage
Revenue                               $ 189.8    $ 163.2    $     26.6         16.3  %
Service/product related costs            41.4       46.4          (5.0 )      (10.8 )
Operating and administrative expenses    30.4       19.4          11.0         56.7
Depreciation and amortization            50.5       43.9           6.6         15.0
Operating income                         67.5       53.5          14.0         26.2
Interest expense, net                     1.8          -           1.8            *
Net income                            $  65.7    $  53.5    $     12.2         22.8  %

* Not meaningful

Revenue. Revenues for the year ended September 30, 2012 were $189.8 million, an increase of $26.6 million, or 16.3%, from $163.2 million during fiscal 2011.

Revenues from firm storage were $94.5 million for the year ended September 30, 2012, an increase of $4.1 million, or 4.5%, from $90.4 million during fiscal 2011. Natural gas firm storage revenues increased $0.5 million compared to the prior year period. The acquisition of our Seneca Lake storage facility in July 2011 along with a higher percentage of contracted capacity at the facility during the period contributed to a $3.2 million increase in natural gas firm storage revenues. A reduction in contract rates at our various facilities resulted in a $2.7 million decrease in natural gas firm storage revenues. NGL firm storage revenues also increased $3.5 million due to the contractual /customer mix at our Bath facility.

Revenues from transportation were $28.4 million for the year ended September 30, 2012, an increase of $14.4 million, or 102.9%, from $14.0 million during fiscal 2011. Transportation revenues increased $15.2 million due to the placement into service of our North-South Facilities and $3.6 million due to the acquisition of the East Pipeline. Offsetting these increases is a $4.4 million reduction due to revenues derived from marketing capacity we held on TGP's 300 line, which was historically marketed to Stagecoach storage customers and was not renewed during the current fiscal year.

Revenues from hub services were $14.9 million for the year ended September 30, 2012, an increase of $8.4 million, or 129.2%, from $6.5 million during fiscal 2011. This increase resulted primarily from additional demand for interruptible wheeling service as a result of customer demand to move gas to and from our interconnecting pipes primarily due to increasing natural gas development in Pennsylvania. Additionally, hub services revenue increased $1.1 million due to insurance reimbursements related to the Stagecoach central compressor loss.

Revenues from salt were $52.0 million for the year ended September 30, 2012, a decrease of $0.3 million, or 0.6%, from $52.3 million during fiscal 2011.

Service/Product Related Costs. Service/product related costs, including storage, transportation and salt costs for the year ended September 30, 2012, were $41.4 million, a decrease of $5.0 million, or 10.8%, from $46.4 million during fiscal 2011.

Storage related costs were $5.9 million for the year ended September 30, 2012, a decrease of $3.1 million, or 34.4%, from $9.0 million during fiscal 2011. Storage related costs decreased primarily due to a $3.4 million insurance reimbursement related to the Stagecoach central compressor loss, and an additional decrease of $3.7 million related to the costs incurred in the prior period associated with the Stagecoach central compressor loss, and to a lesser extent a $0.9 million decrease during the period due to a reduction of butane product sales from fiscal 2011. These decreases were partially offset by a $3.9 million increase in storage related costs incurred as a result of placing our North-South Facilities into service in December 2011, and $0.6 million due to lower fuel collections as a result of lower average natural gas prices during the current year.


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Transportation related costs were $5.2 million for the year ended September 30, 2012, a decrease of $1.6 million, or 23.5%, from $6.8 million during fiscal 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 capacity held by us.

Salt related costs were $30.3 million for the year ended September 30, 2012, a decrease of $0.3 million, or 1.0%, from $30.6 million during fiscal 2011.

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 cost of salt sold. Our transportation related costs consist primarily of our costs to procure firm transportation capacity on certain pipelines.

Operating and Administrative Expenses. Operating and administrative expenses were $30.4 million for the year ended September 30, 2012, compared to $19.4 million during fiscal 2011, an increase of $11.0 million, or 56.7%. Operating expenses increased $2.2 million due to the acquisition of our Seneca Lake facility in July 2011, $4.7 million due to an increase in unit based compensation expenses, $1.8 million due to an increase in property taxes and personnel costs at our various facilities, $0.5 million due to placing our North-South Facilities into service in December 2011, $0.7 million due to an increase in acquisition related expenses associated with US Salt, and $0.8 million due to costs related to being a public company.

Depreciation and Amortization. Depreciation and amortization increased to $50.5 million for the year ended September 30, 2012, from $43.9 million during fiscal 2011. This $6.6 million, or 15.0%, increase resulted primarily from the Seneca Lake acquisition in July 2011 and current year depreciation on the North-South Facilities which were placed into full service in December 2011.

Interest Expense. Interest expense was $1.8 million for the year ended September 30, 2012 related to interest incurred on outstanding borrowings on our revolving Credit Facility. There was no interest expense in the prior period due to no outstanding debt, as Inergy funded our operations, prior to our December 2011 IPO.

Net Income. Net income for the year ended September 30, 2012, was $65.7 million compared to net income of $53.5 million during fiscal 2011. The $12.2 million, or 22.8%, increase in net income was primarily attributable to higher revenue and lower service/product related costs during the year ended September 30, 2012, partially offset by increased operating and administrative costs, depreciation and amortization, and interest expenses as discussed above.

EBITDA and Adjusted EBITDA. The following table summarizes EBITDA and Adjusted EBITDA for the years ended September 30, 2012 and 2011, respectively (in millions):

Year Ended
September 30,
2012 2011
EBITDA:
Net income                                          $   65.7    $ 53.5
Depreciation and amortization                           50.5      43.9
Interest expense, net                                    1.8         -
EBITDA                                              $  118.0    $ 97.4
Long-term incentive and equity compensation expense      6.5       1.8
Transaction costs (a)                                    0.7       0.4
Adjusted EBITDA                                     $  125.2    $ 99.6


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                                                        Year Ended
                                                       September 30,
                                                      2012       2011
EBITDA:
Net cash provided by operating activities           $ 132.7     $ 96.3
Net changes in working capital balances                (9.2 )      1.1
Amortization of deferred financing costs               (0.8 )        -
Interest expense, net                                   1.8          -
Long-term incentive and equity compensation expense    (6.5 )        -
EBITDA                                              $ 118.0     $ 97.4
Long-term incentive and equity compensation expense     6.5        1.8
Transaction costs (a)                                   0.7        0.4
Adjusted EBITDA                                     $ 125.2     $ 99.6

(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 . . .

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