News Column

QEP MIDSTREAM PARTNERS, LP - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

May 8, 2014

Unless the context otherwise requires, references in this report to "Predecessor," "we," "our," "us," or like terms, when used on a historical basis (period prior to our IPO on August 14, 2013), refer to QEP Midstream Partners, LP Predecessor. References in this report to "QEP Midstream" the "Partnership," "Successor," "we," "our," "us," or like terms, when used from and after the IPO, in the present tense or prospectively (starting August 14, 2013), refer to QEP Midstream Partners, LP and its subsidiaries. For purposes of this report, "QEP" refers to QEP Resources, Inc. and its consolidated subsidiaries including the Partnership. The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited historical consolidated financial statements and notes in Item 1. Financial Statements contained herein and the Partnership's audited consolidated financial statements for the year ended December 31, 2013, included in our Annual Report on Form 10-K. Among other things, those historical consolidated financial statements include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below as a result of various risk factors, including those that may not be in the control of management. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the section entitled "Risk Factors" included in our Annual Report on Form 10-K. See also Forward-Looking Statements in Item 3 of this report. For a glossary of commonly used terms found in this Quarterly Report on Form 10-Q, please refer to the "Glossary of Terms" provided in the Partnership's 2013 Annual Report on Form 10-K.



Overview

QEP Midstream Partners, LP (NYSE: QEPM) is a master limited partnership formed by QEP Resources, Inc. (NYSE: QEP) to own, operate, acquire and develop midstream energy assets.

On August 14, 2013, the Partnership's common units began trading on the NYSE after the completion of the IPO of 20,000,000 common units at a price to the public of $21.00 per common unit. Following the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units, at a price of $21.00 per common unit. The Partnership received net proceeds of $449.6 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and offering expenses totaling approximately $33.4 million. The Partnership used the net proceeds to repay its outstanding debt balance to QEP, pay revolving credit facility origination fees and make a cash distribution to QEP, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to the Partnership. The Partnership's assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines through which we provide natural gas and crude oil gathering and transportation services. Our assets are located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the portion of the Williston Basin located in North Dakota and consist of the following assets: Green River System Green River Gathering Assets. The Green River Gathering Assets are comprised of 373 miles of natural gas gathering pipelines, 56 miles of crude oil gathering pipelines, 88 miles of water gathering pipelines and a 61-mile, FERC-regulated crude oil pipeline located in the Green River Basin. These assets have a total natural gas throughput capacity of 737 MMcf/d, total crude oil and condensate throughput capacity of 7,137 Bbls/d, total water throughput capacity of 21,990 Bbls/d, and a total of 40,800 Bbls/d throughput capacity on our FERC-regulated pipeline. Rendezvous Gas. Rendezvous Gas is a joint venture between QEP Midstream and Western Gas Partners, LP (Western Gas), which was formed to own and operate the infrastructure that transports gas from the Pinedale and Jonah fields to several re-delivery points, including natural gas processing facilities that are owned by QEP Field Services or Western Gas. The Rendezvous Gas assets consist of three parallel, 103-mile high-pressure natural gas pipelines, with 1,032 MMcf/d of aggregate throughput capacity and 7,800 bhp of gas compression. We own a 78% interest in Rendezvous Gas. Rendezvous Pipeline. Rendezvous Pipeline's sole asset is a 21-mile, FERC-regulated natural gas transmission pipeline that provides gas transportation services from QEP Field Services' Blacks Fork processing complex in southwest Wyoming to an interconnect with the Kern River Pipeline. Rendezvous Pipeline has total throughput capacity of 450 MMcf/d. 14

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Vermillion Gathering System. The Vermillion Gathering System consists of

gas gathering and compression assets located in southern Wyoming, northwest Colorado and northeast Utah, which, when combined, include 517 miles of low-pressure, gas gathering pipelines and 23,932 bhp of gas



compression. The Vermillion Gathering System has combined total throughput

capacity of 212 MMcf/d.

Three Rivers Gathering System. Three Rivers Gathering is a joint venture

between QEP Midstream and Ute Energy Midstream Holdings, LLC that was

formed to transport natural gas from the Uinta Basin area to a processing

facility owned by QEP Field Services and third parties. The Three Rivers

Gathering System consists of gas gathering assets located in the Uinta

Basin in northeast Utah, including approximately 52 miles of gathering

pipeline and 4,735 bhp of gas compression. The Three Rivers Gathering

System has total throughput capacity of 212 MMcf/d. We own a 50% interest

in Three Rivers Gathering.

Williston Gathering System. The Williston Gathering System is a crude oil

and natural gas gathering system located in the Williston Basin in McLean

County, North Dakota. The Williston Gathering System includes 17 miles of

gas gathering pipelines, 17 miles of oil gathering pipelines, 239 bhp of

gas compression, and a crude oil and natural gas handling facility,

located primarily on the Fort Berthold Indian Reservation. The Williston

Gathering System has total crude oil throughput capacity of 7,000 Bbls/d

and total natural gas throughput capacity of 3 MMcf/d.

In addition to the above assets, our Predecessor's assets included a 38% equity interest in Uintah Basin Field Services and a 100% interest in the Uinta Basin Gathering System. These assets were retained by QEP Field Services and were not part of the assets conveyed to the Partnership in connection with the IPO. The Results of Operations discussed below include historical information that relates to operations prior to the date of the IPO, which represents our Predecessor and includes combined results for both the properties conveyed to the Partnership in connection with the IPO and the properties retained by our Predecessor. We have included pro forma historical data limited to only the properties conveyed to us in connection with the IPO, as we believe such data is more useful to the reader to better understand trends in our operations.



Recent Developments

In December 2013, QEP's Board of Directors authorized QEP's management to develop a plan to separate the Company's midstream business, including the ownership and control of QEP Field Services, which include its general and limited partner interests in QEP Midstream. We believe there is nothing in QEP's announced strategy to separate its midstream business that precludes QEP Field Services from offering us acquisition opportunities to purchase additional midstream assets from it or to jointly pursue midstream acquisitions with it prior to or subsequent to the separation. Further, we do not believe QEP's acreage dedicated to our assets will be changed significantly due to the separation, and we believe these acreage dedications will continue to provide us a platform for future organic growth from our existing assets. In May 2014, the Partnership entered into a purchase and sale agreement to acquire 40% of the membership interests in Green River Processing, LLC (Green River Processing) for $230.0 million, subject to customary purchase price adjustments, (the Green River Processing Acquisition) from QEP Field Services. The Green River Processing Acquisition is expected to close in July 2014 and will be funded with borrowings under the Credit Facility.



Our Operations

Our results are driven primarily by the volumes of oil and natural gas we gather and the fees charged for such services. We connect wells to gathering lines through which (i) oil may be delivered to a downstream pipeline and ultimately to end-users and (ii) natural gas may be delivered to a processing plant, treating facility or downstream pipeline, and ultimately to end-users. We generally do not take title to the oil and natural gas that we gather or transport. We provide all of our gathering services pursuant to fee-based agreements, the majority of which have annual inflation adjustment mechanisms. Under these arrangements, we are paid a fixed or margin-based fee with respect to the volume of the oil and natural gas we gather. This type of contract provides us with a relatively steady revenue stream that is not subject to direct commodity price risk, except to the extent that we retain and sell condensate that is recovered during the gathering of natural gas from the wellhead. For the three months ended March 31, 2014, approximately 7% of our Partnership's revenue was generated through the sale of condensate volumes that we collect on our gathering systems. Although the Partnership has entered into a fixed price condensate sales agreement with QEP, we still have indirect exposure to commodity price risk in that persistent low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the volumes of oil and natural gas available for gathering by our systems. Refer to Item 3 for a discussion of our exposure to commodity price risk through our condensate recovery and sales. 15 -------------------------------------------------------------------------------- We have secured significant acreage dedications from several of our largest customers, including QEP. We believe that drilling activity on acreage dedicated to us should, in the aggregate, maintain or increase our existing throughput levels and offset the natural production declines of the wells currently connected to our gathering systems. Specifically, our customers have dedicated all of the oil and natural gas production they own or control from (i) wells that are currently connected to our gathering systems and are located within the acreage dedication and (ii) future wells that are drilled during the term of the applicable gathering contract and located within the dedicated acreage in which our gathering systems currently exist or could be expanded to connect to additional wells. We provide a portion of our gathering and transportation services on our Three Rivers and Williston gathering systems through firm contracts with minimum volume commitments, which are designed to ensure that we will generate a certain amount of revenue over the life of the gathering agreement by collecting either gathering fees for actual throughput or deficiency payments to cover any shortfall.



How We Evaluate Our Business

Our management uses a variety of financial and operating metrics to analyze our performance including: (i) throughput volumes; (ii) gathering expenses; (iii) maintenance and expansion capital expenditures; (iv) Adjusted EBITDA; and (v) Distributable Cash Flow. Both Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures.



Throughput volumes

The amount of revenue we generate depends primarily on the volumes of natural gas and crude oil that we gather for our customers. The volumes transported on our gathering pipelines are driven by upstream development drilling activity and production volumes from the wells connected to our gathering pipelines. Producers' willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of oil, natural gas and natural gas liquids (NGL), the cost to drill and operate a well, the availability and cost of capital and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in natural gas, oil and NGL prices.



Gathering expenses

We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs, compression costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. These expenses generally remain relatively stable across broad ranges of throughput volumes but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses.



Maintenance and Expansion Capital Expenditures

We define maintenance capital expenditures as those that will enable us to maintain our operating capacity or operating income over the long term and expansion capital expenditures as those that we expect will increase our operating capacity or operating income over the long-term. We schedule our ongoing, routine operating and maintenance capital expenditures on our gathering systems throughout the calendar year to avoid significant variability in our cash flows and maintain safe operations. There is typically some seasonality in our expenditures as we generally reduce routine maintenance in the winter months due to weather conditions. We actively seek new opportunities to add throughput to our systems by expanding the geographic areas covered by our gathering systems, connecting new wells to the systems and installing additional compression. We analyze the expected return on expansion capital expenditures and attempt to negotiate terms in our gathering agreements that ensure we will receive an acceptable rate of return on those expenditures.



Adjusted EBITDA and Distributable Cash Flow (Non-GAAP)

We define Adjusted EBITDA as net income attributable to the Partnership or the Predecessor before depreciation and amortization, interest and other income and expense, gains and losses from asset sales, deferred revenue associated with minimum volume commitment payments and certain other non-cash and/or non-recurring items. We define Distributable Cash Flow as Adjusted EBITDA less net cash interest paid, maintenance capital expenditures and cash adjustments related to equity 16 --------------------------------------------------------------------------------



method investments and non-controlling interests, and other non-cash expenses. Distributable Cash Flow does not reflect changes in working capital balances.

Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures used by management and by external users of our financial statements, such as investors and commercial banks, to assess:

our operating performance as compared to those of other companies in the

midstream sector, without regard to financing methods, historical cost basis or capital structure; the ability of our assets to generate sufficient cash flow to make distributions to our partners;



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 of various investment opportunities.

We believe that the presentation of Adjusted EBITDA and Distributable Cash Flow provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and Distributable Cash Flow are net income attributable to the Partnership or the Predecessor and net cash provided by operating activities, respectively. Adjusted EBITDA and Distributable Cash Flow should not be considered an alternative to net income attributable to the Partnership or the Predecessor, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and Distributable Cash Flow excludes some, but not all, items that affect net income attributable to the Partnership or the Predecessor and net cash provided by operating activities, and these measures may vary among other companies. As a result, Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other companies.



General Trends and Outlook

We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.



Oil and natural gas supply and demand

Our gathering operations are primarily dependent upon oil and natural gas production from the upstream sector in our areas of operation. The decline in natural gas prices over the prior years has caused a related decrease in natural gas drilling in the United States. In addition, there is a natural decline in production from existing wells that are connected to our gathering systems. However, in the areas in which we operate, there remains a consistent level of drilling activity due to the liquids content of the natural gas that we believe will offset the production and drilling declines seen in other areas. Although we anticipate continued high levels of exploration and production activities in all of the areas in which we operate, we have no control over this activity. Fluctuations in oil and natural gas prices could affect production rates over time and levels of investment by QEP and third parties in exploration for and development of new oil and natural gas reserves.



Rising operating costs and inflation

The current level of exploration, development and production activities across the United States has resulted in increased competition for personnel and equipment. This is causing increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We attempt to recover increased costs from our customers, but there may be a delay in doing so or we may be unable to recover all these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.



Impact of interest rates

Interest rates have been volatile in recent years. If interest rates rise, our future financing costs will increase accordingly. In addition, because our common units are yield-based securities, rising market interest rates could impact the relative attractiveness of our common units to investors, which could limit our ability to raise funds, or increase the price of raising funds, in the capital markets and may limit our ability to expand our operations or make future acquisitions. 17 --------------------------------------------------------------------------------



Regulatory compliance

The regulation of oil and natural gas transportation activities by the FERC, and other federal and state regulatory agencies, including the Department of Transportation (the DOT), has a significant impact on our business. For example, the Pipeline and Hazardous Materials Safety Administration office of the DOT establishes pipeline integrity management programs that could require more frequent inspections of pipeline facilities and other preventative measures, which may increase our compliance costs and increase the time it takes to obtain required permits. FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation of oil and natural gas. Our operations are also impacted by new regulations, which may increase the time that it takes to obtain required permits. Additionally, increased regulation of oil and natural gas producers in our areas of operations, including regulation associated with hydraulic fracturing, could reduce regional supply of oil and natural gas and therefore throughput on our gathering systems. Acquisition opportunities We may acquire additional midstream assets from QEP Field Services or third parties. If QEP Field Services chooses to pursue midstream asset sales, it is under no contractual obligation to offer assets or business opportunities to us. In addition, we may pursue selected asset acquisitions from third parties to the extent such acquisitions complement our or QEP's existing asset base. In addition to our existing areas of operation, we may diversify our business through acquisition and greenfield development opportunities in geographic regions where neither QEP nor we currently operate. We believe that we will be well-positioned to acquire midstream assets from third parties should opportunities arise. If we do not make acquisitions from QEP Field Services or third parties on economically acceptable terms, our future growth will be limited. Furthermore, acquisitions we do make could reduce, rather than increase, our cash generated from operations on a per-unit basis. Factors Affecting the Comparability of Our Financial Results



The Partnership's results of operations subsequent to the IPO will not be comparable to the Predecessor's historical results of operations for the reasons described below.

Assets not included in the Partnership

The Predecessor's results of operations prior to the IPO include revenues and expenses relating to QEP Field Services' ownership of the Uinta Basin Gathering System and general support equipment. These assets were retained by QEP Field Services and were not contributed to the Partnership in connection with the IPO.



General and administrative expenses

For the three months ended March 31, 2013, the Predecessor incurred $5.7 million in general and administrative expenses. The Predecessor's general and administrative expenses included costs allocated by QEP. These costs were reimbursed and related to: (i) various business services, including, but not limited to, payroll, accounts payable and facilities management, (ii) various corporate services, including, but not limited to, legal, accounting, treasury, information technology and human resources, and (iii) compensation, share-based compensation, benefits and pension and post-retirement costs. General and administrative expenses were allocated to the Predecessor based on its proportionate share of QEP's gross property, plant and equipment, operating income and direct labor costs. Management believes these allocation methodologies were reasonable. In accordance with the Omnibus Agreement, QEP charges the Partnership a combination of direct and allocated charges for administrative and operational services. The annual fee is currently set at $13.8 million. For the three months ended March 31, 2014, the Partnership incurred $3.5 million of such administrative and operational services expenses. In addition to the charges under the Omnibus Agreement, we anticipate incurring approximately $2.5 million per year of incremental general and administrative expenses attributable to operating as a publicly traded partnership, such as expenses associated with annual, quarterly and current reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; outside director fees; and director and officer insurance expenses. These incremental general and administrative expenses are not reflected in our historical consolidated financial statements prior to the IPO. The Partnership's general and administrative expense also includes compensation expense associated with the LTIP, which was implemented in connection with the IPO. For the three months ended March 31, 2014, the Partnership incurred $1.2 million of incremental G&A expenses. 18 --------------------------------------------------------------------------------



Working capital

The impact of all affiliated transactions of the Predecessor historically has been net settled within QEP's consolidated financial statements because these transactions related to QEP and were funded by QEP's working capital. Third-party transactions were also funded by QEP's working capital. Since the IPO, all affiliate and third-party transactions have been funded by our working capital. This impacts the comparability of our cash flow statements, working capital analysis and liquidity discussion.



Interest expense

Prior to the IPO, we incurred interest expense on intercompany notes payable to QEP that was allocated to us. These balances were repaid in full with a portion of the proceeds from the IPO; therefore, interest expense attributable to these balances and reflected in our historical consolidated financial statements will not be incurred in the future. In connection with the IPO, we entered into a $500.0 million revolving credit facility agreement, which contains customary short-term interest rates and a commitment fee on the unused portion of the facility.



Cash distributions to unitholders

The Partnership expects to make quarterly cash distributions to our unitholders and our General Partner at our minimum quarterly distribution amount of $0.25 per unit ($1.00 per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our General Partner most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including borrowings under our credit facility and debt and equity issuances, to fund our acquisition and expansion capital expenditures. Historically, we largely relied on internally generated cash flows and advances under intercompany loans from QEP to satisfy our capital expenditure requirements. 19 -------------------------------------------------------------------------------- Results of Operations The discussion of our historic performance and financial condition is presented for the Partnership (Successor), for the three months ended March 31, 2014, and for the Predecessor for the three months ended March 31, 2013. As previously discussed, the historic financial information of the Predecessor contained in this report relates to periods that ended prior to the completion of the IPO, and includes results for both the properties conveyed to the Partnership in connection with the IPO and properties retained by our Predecessor. We believe that historical data limited to only the properties conveyed to the Partnership in connection with the IPO, adjusted for transactions that occurred as a result of the IPO, is relevant and meaningful, enhances the discussion of the periods presented and is useful to the reader to better understand trends in our operations. Therefore, we have also included the results of operations for the three months ended March 31, 2013 on a pro forma basis. The following pro forma financial data is for informational purposes only and was derived from the Predecessor financial information adjusted to give effect to events and circumstances that are directly attributed to the IPO transaction as if it had occurred on January 1, 2013, that are factually supportable and, with respect to the Consolidated Statement of Income, are expected to have a continuing impact on the consolidated results. These adjustments include: removing the results of the assets retained by the Predecessor, consisting of the Uinta Basin Gathering System and general support equipment; an adjustment to general and administrative expense for the estimated incremental expenses that would have occurred as a result of operating as a public company and the entry into the Omnibus Agreement concurrent with the IPO; and an adjustment to interest expense to eliminate the related party debt that was settled in conjunction with the IPO and to estimate interest expense related to the Credit Facility entered into in connection with the IPO. The unaudited pro forma information should not be relied upon as necessarily being indicative of the results that may be obtained in the future. Refer to "Factors Affecting the Comparability of Our Financial Results" above for a description of the significant factors affecting the comparability of the Predecessor's historical results of operations and those of the Partnership subsequent to the IPO. 20 -------------------------------------------------------------------------------- Three Months Ended March 31, 2014



Three Months Ended March 31, 2013

Predecessor As Pro Forma Successor Reported Adjustments (3) Pro Forma (in millions, except operating and per unit amounts) Revenues Gathering and transportation $ 28.9 $ 36.6 $ (7.6 ) $ 29.0 Condensate sales 2.1 3.5 (1.5 ) 2.0 Total revenues 31.0 40.1 (9.1 ) 31.0 Operating expenses Gathering expense 6.4 7.7 (1.9 ) 5.8 General and administrative 4.7 5.7 (1.2 ) (4) 4.5 Taxes other than income taxes 0.5 0.3 (0.1 ) 0.2 Depreciation and amortization 7.8 10.3 (2.6 ) 7.7 Total operating expenses 19.4 24.0 (5.8 ) 18.2 Net loss from property sales - (0.3 ) 0.3 - Operating income 11.6 15.8 (3.0 ) 12.8 Income from unconsolidated affiliates 1.5 1.3 (0.7 ) 0.6 Interest expense (0.6 ) (1.1 ) 0.5 (5) (0.6 ) Net income 12.5 16.0 (3.2 ) 12.8 Net income attributable to noncontrolling interest (0.8 ) (0.6 ) - (0.6 ) Net income attributable to QEP Midstream or Predecessor $ 11.7 $ 15.4 $ (3.2 ) $ 12.2 Operating Statistics Natural gas throughput in millions of MMBtu Gathering and transportation 69.8 90.6 (18.1 ) 72.5 Equity interest (1) 5.2 3.3 (0.4 ) 2.9 Total natural gas throughput 75.0 93.9 (18.5 ) 75.4 Throughput attributable to noncontrolling interests(2) (2.6 ) (2.6 ) - (2.6 ) Total throughput attributable to QEP Midstream or Predecessor 72.4 91.3 (18.5 ) 72.8 Crude oil and condensate gathering system throughput volumes (in MBbls) 1,070.1 1,278.8 - 1,278.8 Water gathering volumes (in MBbls) 1,075.8 870.1 - 870.1 Condensate sales volumes (in MBbls) 25.0 42.7 (19.4 ) 23.3



Price

Average gas gathering and transportation fee (per MMBtu) $ 0.31 $ 0.34 $ 0.33 Average oil and condensate gathering fee (per barrel) $ 2.36 $ 2.02 $ 2.02 Average water gathering fee (per barrel) $ 1.85 $ 1.80 $ 1.80 Average condensate sale price (per barrel) $ 85.25 $ 82.99$ 84.42 Non-GAAP Measures Adjusted EBITDA (6) $ 19.4 $ 26.4 $ (6.6 ) $ 19.8 Distributable Cash Flow (6) $ 17.4



(1) Includes our 50% share of gross volumes from Three Rivers Gathering and the

Predecessor's 38% share of gross volumes from Uintah Basin Field Services.

(2) Includes the 22% noncontrolling interest in Rendezvous Gas.



(3) Pro forma adjustments reflect operating results related to assets retained

by our Predecessor following the IPO, except as otherwise noted. (4) The pro forma adjustment for general and administrative includes the estimated incremental expenses that would have occurred as a results of



operating as a public company and the entry into the Omnibus Agreement

concurrent with the IPO.

(5) The pro forma adjustment for interest expense reflects the elimination of

historical interest expense due to QEP as the related party debt was

settled concurrent with the IPO and includes the estimated interest expense

related to the Credit Facility, which was entered in conjunction with the

IPO, which includes amortization of deferred finance cost and commitment

fees on the unused portion of the Credit Facility. (6) Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial



measures. See "Adjusted EBITDA and Distributable Cash Flow (Non-GAAP)" for

definitions of these non-GAAP financial measures and reconciliations to the

most directly comparable GAAP financial measures. 21

-------------------------------------------------------------------------------- Successor Results of Operations On August 14, 2013, the Partnership completed its IPO. Prior to the IPO, QEP Field Services and the General Partner contributed, as capital contributions, $407.8 million of net assets representing their limited liability company interest in the Operating Company. The contribution of QEP Field Services' and the General Partners' limited liability interest in the Operating Company to the Partnership was valued using the carryover book value of the Operating Company, as the transaction is a transfer of assets between entities under common control. The Partnership's assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines and exclude the Uinta Basin Gathering System and general support equipment, which were retained by QEP Field Services. The Partnership's (Successor's) operating results for the quarter ended March 31, 2014 are presented below.



Three Months Ended March 31, 2014 - Successor

Revenue

Gathering and transportation. Gathering and transportation revenues were $28.9 million for the three months ended March 31, 2014. Natural gas gathering and transportation revenue was $21.5 million with throughput of 69.8 million MMBtu and an average gas gathering and transportation fee of $0.31 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 47.0 million MMBtu of throughput, and our Vermillion Gathering System, which contributed throughput of 11.0 million MMBtu. Crude oil and condensate gathering revenue was $2.5 million for the three months ended March 31, 2014. The average gathering fee was $2.36 per bbl and throughput was 1,070.1 Mbbls of which 800.4 Mbbls was attributable to our Green River Gathering System and 269.7 Mbbls was attributable to our Williston Gathering System. Water gathering revenue was $2.0 million for the three months ended March 31, 2014, with throughput of 1,075.8 Mbbls and an average fee of $1.85 per bbl at our Green River Gathering System.



The remaining portion of gathering and transportation revenue for the three months ended March 31, 2014, related to deficiency revenue of $2.9 million, all of which was attributable to the Williston Gathering System.

Condensate sales. Revenue from condensate sales was $2.1 million for the three months ended March 31, 2014. Sales volumes were 25.0 Mbbls at a fixed price of $85.25 per barrel pursuant to our fixed price sales agreement with QEP. Operating Expenses



Gathering expense. Gathering expense was $6.4 million for the three months ended March 31, 2014, the majority of which was incurred on our Green River and Vermillion Gathering Systems.

General and administrative. General and administrative expenses were $4.7 million for the three months ended March 31, 2014, consisting of $3.5 million from charges under the Omnibus Agreement, $0.4 million for equity-based compensation expense and $0.8 million related to operating as a publicly traded partnership, including fees for external audit procedures. Taxes other than income taxes. Taxes other than income taxes were $0.5 million for the three months ended March 31, 2014, primarily attributable to property tax expense on our gathering systems.



Depreciation and amortization. Depreciation and amortization expenses were $7.8 million for the three months ended March 31, 2014.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates was $1.5 million for the three months ended March 31, 2014, related to income from our ownership in Three Rivers Gathering. Interest expense. Interest expense was $0.6 million for the three months ended March 31, 2014, which consisted of $0.4 million related to commitment fees paid on the unused portion of the Credit Facility and $0.2 million related to the amortization of debt issuance costs. There were no borrowings under the Credit Facility during the period. 22

-------------------------------------------------------------------------------- Predecessor Results of Operations The Predecessor financial statements were prepared in connection with the IPO. The Predecessor consisted of all of the Partnership's gathering assets as well as the Uinta Basin Gathering System and general support equipment. The Uinta Basin Gathering System and general support equipment were retained by QEP and were not part of the assets conveyed to the Partnership.



Three Months Ended March 31, 2013 - Predecessor

Revenue

Gathering and transportation. Gathering and transportation revenues were $36.6 million for the three months ended March 31, 2013. Natural gas gathering and transportation revenue was $31.2 million with throughput of 90.6 million MMBtu and an average gas gathering and transportation fee of $0.34 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 47.4 million MMBtu of throughput; the Predecessor's Uinta Basin Gathering System, with throughput of 18.1 million MMBtu; and our Vermillion Gathering System, with throughput of 13.1 million MMBtu. Crude oil and condensate gathering revenue was $2.6 million for the three months ended March 31, 2013, as a result of an average gathering fee of $2.02 per bbl and throughput of 1,278.8 Mbbls of which 972.6 Mbbls was attributable to our Green River Gathering System and 306.2 Mbbls was attributable to our Williston Gathering System. Water gathering revenue consisted of $1.6 million for the three months ended March 31, 2013, from throughput of 870.1 Mbbls and an average fee of $1.80 per bbl at our Green River Gathering System.



The remaining portion of gathering and transportation revenue for the three months ended March 31, 2013, related to deficiency revenue of $1.2 million, all of which was attributable to the Williston Gathering System.

Condensate sales. Revenue from condensate sales was $3.5 million for the three months ended March 31, 2013, from sales volumes of 42.7 Mbbls at a price of $82.99 per bbl, all of which was attributable to the Predecessor's Uinta and Vermillion Gathering Systems. Operating Expenses Gathering expense. Gathering expense was $7.7 million for the three months ended March 31, 2013, the majority of which was incurred on the Predecessor's Green River, Uinta Basin and Vermillion Gathering Systems.



General and administrative. General and administrative expenses were $5.7 million for the three months ended March 31, 2013, from the allocation of costs by QEP for various business and corporate services and compensation related expenses.

Taxes other than income taxes. Taxes other than income taxes were $0.3 million for the three months ended March 31, 2013, primarily attributable to property tax expense on the Predecessor's gathering systems.



Depreciation and amortization. Depreciation and amortization expenses were $10.3 million for the three months ended March 31, 2013.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates was $1.3 million for the three months ended March 31, 2013. Of the $1.3 million, income from the Predecessor's ownership in Uintah Basin Field Services was $0.7 million and income from our ownership in Three Rivers Gathering was $0.6 million. Interest expense. Interest expense was $1.1 million for the three months ended March 31, 2013, related to interest charged on the Predecessor's outstanding long-term debt with QEP during the period. 23 -------------------------------------------------------------------------------- Supplemental Pro Forma Analysis As previously discussed, the historic financial information of the Predecessor contained in this report relates to periods that ended prior to the completion of the IPO, and includes results for both the properties conveyed to the Partnership in connection with the IPO and properties retained by our Predecessor. We believe that historical data limited to only the properties conveyed to the Partnership in connection with the IPO and that reflects transactions that occurred as a result of the IPO is relevant and meaningful, enhances the discussion of the periods presented and is useful to the reader to better understand trends in our operations. Therefore, we have also included the results of operations for the three months ended March 31, 2013, on a pro forma basis.



Supplemental Pro Forma Analysis - Successor Three Months Ended March 31, 2014, Compared to Pro Forma Three Months Ended March 31, 2013

Revenue

Gathering and transportation. Gathering and transportation revenues decreased by $0.1 million during the three months ended March 31, 2014, compared to the pro forma three months ended March 31, 2013. Natural gas gathering and transportation revenues decreased $2.0 million, due to a lower gas gathering throughput of 2.7 million MMBtu and a 6% lower gas gathering rate. The decrease in throughput was primarily attributable to a 2.1 million MMBtu decrease at the Vermillion Gathering System and a 0.4 million MMBtu decrease at the Green River Gathering System, both related to lower production from these areas. Crude oil and condensate gathering revenue was slightly lower in the first three months of 2014 compared to the pro forma three months ended March 31, 2013, due to a 16% decrease in gathering volume offset by a 17% increase in price due to an increase in volumes gathered from customers with higher gathering rates. Water gathering revenue increased by $0.4 million, or 27%, due to a 24% increase in gathering volume and a 3% increase in rate on the Green River Gathering System. Deficiency revenue increased by $1.7 million during the three months ended March 31, 2014, compared to the pro forma three months ended March 31, 2013, due to higher deficiency revenue attributable to the Williston Gathering System. Condensate sales. Condensate sales increased by $0.1 million during the three months ended March 31, 2014, compared to the pro forma three months ended March 31, 2013, due to a 7% increase in sales volumes and a 1% increase in price as a result of our fixed-price sales agreement with QEP.



Operating Expenses

Gathering expense. Gathering expense increased by $0.6 million, or 10% during the three months ended March 31, 2014, compared to the pro forma three months ended March 31, 2013, due to increased labor and maintenance costs at our Vermillion and Williston Gathering Systems. General and administrative. General and administrative expenses for the first three months of 2014 increased by $0.2 million, or 4%, compared to the pro forma three months ended March 31, 2013, due to equity-based compensation expense that was recognized during the three months ended March 31, 2014, related to common unit grants under our LTIP that vest immediately and are non-forfeitable. See Note 8 - Equity-Based Compensation, for additional information on the first quarter 2014 grants. Taxes other than income taxes. Taxes other than income taxes increased by $0.3 million during the three months ended March 31, 2014, compared to the pro forma three months ended March 31, 2013, due to a tax refund in the first quarter of 2013 related to our Vermillion Gathering System.



Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates increased by $0.9 million during the three months ended March 31, 2014, compared to the pro forma three months ended March 31, 2013, due to deficiency revenue recognized in the first quarter of 2014 from our ownership in Three Rivers Gathering. 24 -------------------------------------------------------------------------------- Interest expense. Interest expense during the three months ended March 31, 2014, was consistent with the pro forma three months ended March 31, 2013, as the pro forma adjustments include the assumption that related party debt was settled and that a consistent interest expense, including commitment fees and amortization of debt financing costs, would have been paid in the first quarter of 2013, as there would have been no borrowings under the Credit Facility. 25 --------------------------------------------------------------------------------



Adjusted EBITDA and Distributable Cash Flow (Non-GAAP)

We define Adjusted EBITDA as net income attributable to the Partnership or the Predecessor before depreciation and amortization, interest and other income and expense, gains and losses from asset sales, deferred revenue associated with minimum volume commitment payments and other non-cash and/or non-recurring items. We define Distributable Cash Flow as Adjusted EBITDA less net cash interest paid, maintenance capital expenditures and cash adjustments related to equity method investments and non-controlling interests, and other non-cash expenses. Distributable Cash Flow does not reflect changes in working capital balances. We believe that the presentation of Adjusted EBITDA and Distributable Cash Flow provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and Distributable Cash Flow are net income attributable to the Partnership or the Predecessor and net cash provided by operating activities, respectively. The following tables present unaudited reconciliations of Adjusted EBITDA and Distributable Cash Flow to net income attributable to the Partnership or the Predecessor, as applicable, and net cash provided by operating activities for each of the periods indicated.


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Source: Edgar Glimpses


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