Attached files
| file | filename |
|---|---|
| EX-31.1 - EXHIBIT - QEP Midstream Partners, LP | qepm-2013930xex311.htm |
| EX-32.1 - EXHIBIT - QEP Midstream Partners, LP | qepm-2013930xex321.htm |
| EX-31.2 - EXHIBIT - QEP Midstream Partners, LP | qepm-2013930xex312.htm |
| EX-10.9 - EXHIBIT - QEP Midstream Partners, LP | qepm-201393013ex109.htm |
| EXCEL - IDEA: XBRL DOCUMENT - QEP Midstream Partners, LP | Financial_Report.xls |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2013
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ______ to ______
Commission File Number: 333-188487
QEP MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter)
STATE OF DELAWARE | 80-0918184 | |
(State or other jurisdiction of | (I.R.S. Employer | |
incorporation or organization) | Identification No.) | |
1050 17th Street, Suite 500, Denver, Colorado 80265
(Address of principal executive offices)
Registrant’s telephone number, including area code: (303) 672-6900
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 o No ý
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 (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
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 the definitions of “large accelerated filer,” “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act:
Large accelerated filer | o | Accelerated filer | o |
Non-accelerated filer | ý (Do not check if a smaller reporting company) | Smaller reporting company | o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
There were 26,705,000 common units, 26,705,000 subordinated units and 1,090,000 general partner units outstanding on October 31, 2013.
QEP Midstream Partners, LP
Form 10-Q for the Quarter Ended September 30, 2013
TABLE OF CONTENTS
Page | |||
ITEM 1. | |||
ITEM 2. | |||
ITEM 3. | |||
ITEM 4. | |||
ITEM 1. | |||
ITEM 1A. | |||
ITEM 2. | |||
ITEM 3. | |||
ITEM 4. | |||
ITEM 5. | |||
ITEM 6. | |||
1
Explanatory Note
Certain information in this report includes periods prior to the completion of QEP Midstream Partners, LP's initial public offering ("IPO") and prior to the effective dates of the agreements discussed herein. Consequently, the unaudited consolidated financial statements and related discussion of financial condition and results of operations contained in this report include periods that pertain to QEP Midstream Partners, LP Predecessor, our predecessor for accounting purposes. Because the results of our predecessor include results for both the properties conveyed to us in connection with our IPO and properties retained by our predecessor, we do not consider these results of our predecessor to be indicative of our future results.
Unless the context otherwise requires, references in this report to "Predecessor," "we," "our," "us," or like terms, when used on a historical basis (periods prior to 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 August 14, 2013, 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.
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
QEP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||
September 30, 2013 | September 30, 2013 | |||||||||||||||||||||||
Period From August 14, 2013, through September 30, 2013 | Period From July 1, 2013, through August 13, 2013 | Three Months Ended September 30, 2012 | Period From August 14, 2013, through September 30, 2013 | Period From January 1, 2013, through August 13, 2013 | Nine Months Ended September 30, 2012 | |||||||||||||||||||
Successor | Predecessor | Predecessor | Successor | Predecessor | Predecessor | |||||||||||||||||||
(in millions, except per unit amounts) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Gathering and transportation | $ | 16.2 | $ | 19.2 | $ | 39.4 | $ | 16.2 | $ | 92.9 | $ | 113.4 | ||||||||||||
Condensate sales | 0.2 | 0.9 | 1.4 | 0.2 | 7.4 | 9.0 | ||||||||||||||||||
Total revenues | 16.4 | 20.1 | 40.8 | 16.4 | 100.3 | 122.4 | ||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||
Gathering | 3.1 | 3.7 | 7.7 | 3.1 | 19.7 | 21.6 | ||||||||||||||||||
General and administrative | 1.5 | 3.2 | 4.9 | 1.5 | 13.6 | 12.6 | ||||||||||||||||||
Taxes other than income taxes | 0.3 | 0.4 | 0.8 | 0.3 | 1.3 | 2.4 | ||||||||||||||||||
Depreciation and amortization | 4.1 | 4.9 | 10.1 | 4.1 | 25.0 | 29.8 | ||||||||||||||||||
Total operating expenses | 9.0 | 12.2 | 23.5 | 9.0 | 59.6 | 66.4 | ||||||||||||||||||
Net loss from property sales | — | (0.1 | ) | — | — | (0.5 | ) | — | ||||||||||||||||
Operating income | 7.4 | 7.8 | 17.3 | 7.4 | 40.2 | 56.0 | ||||||||||||||||||
Income from unconsolidated affiliates | — | 0.4 | 2.3 | — | 3.8 | 5.5 | ||||||||||||||||||
Interest expense | (0.3 | ) | (0.5 | ) | (1.4 | ) | (0.3 | ) | (2.6 | ) | (5.4 | ) | ||||||||||||
Net income | 7.1 | 7.7 | 18.2 | 7.1 | 41.4 | 56.1 | ||||||||||||||||||
Net income attributable to noncontrolling interest | (0.6 | ) | (0.6 | ) | (1.0 | ) | (0.6 | ) | (2.5 | ) | (2.7 | ) | ||||||||||||
Net income attributable to QEP Midstream or Predecessor | $ | 6.5 | $ | 7.1 | $ | 17.2 | $ | 6.5 | $ | 38.9 | $ | 53.4 | ||||||||||||
Net income attributable to QEP Midstream per limited partner unit (basic and diluted): | ||||||||||||||||||||||||
Common units | $ | 0.12 | $ | 0.12 | ||||||||||||||||||||
Subordinated units | $ | 0.12 | $ | 0.12 | ||||||||||||||||||||
Weighted-average limited partner units outstanding (basic and diluted): | ||||||||||||||||||||||||
Common units | 26.7 | 26.7 | ||||||||||||||||||||||
Subordinated units | 26.7 | 26.7 | ||||||||||||||||||||||
See notes accompanying the unaudited consolidated financial statements.
3
QEP MIDSTREAM PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, 2013 | December 31, 2012 | |||||||
Successor | Predecessor | |||||||
(in millions) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 15.9 | $ | 1.4 | ||||
Accounts receivable, net | 4.9 | 18.2 | ||||||
Accounts receivable from related party | 15.0 | 24.9 | ||||||
Natural gas imbalance receivable | 2.1 | 2.2 | ||||||
Other current assets | — | 0.1 | ||||||
Total current assets | 37.9 | 46.8 | ||||||
Property, plant and equipment, net | 486.3 | 634.1 | ||||||
Investment in unconsolidated affiliates | 27.5 | 40.7 | ||||||
Other noncurrent assets | 3.2 | 3.8 | ||||||
Total assets | $ | 554.9 | $ | 725.4 | ||||
LIABILITIES | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 5.7 | $ | 6.3 | ||||
Accounts payable to related party | 4.0 | 3.7 | ||||||
Natural gas imbalance liability | 2.1 | 2.2 | ||||||
Deferred revenue | 7.5 | 0.3 | ||||||
Accrued compensation | — | 1.7 | ||||||
Other current liabilities | 0.7 | 1.3 | ||||||
Total current liabilities | 20.0 | 15.5 | ||||||
Long-term debt (to related party at December 31, 2012) | — | 131.1 | ||||||
Asset retirement obligation | 11.9 | 16.3 | ||||||
Deferred revenue | 6.7 | 10.2 | ||||||
Total long-term liabilities | 18.6 | 157.6 | ||||||
Commitments and contingencies (see Note 9) | ||||||||
EQUITY | ||||||||
Limited partner common units - 26.7 million units issued and outstanding | 408.0 | — | ||||||
Limited partner subordinated units - 26.7 million units issued and outstanding | 59.5 | — | ||||||
General partner units - 1.1 million units issued and outstanding | 2.3 | — | ||||||
Total partners' capital | 469.8 | — | ||||||
Parent net investment | — | 504.6 | ||||||
Noncontrolling interest | 46.5 | 47.7 | ||||||
Total net equity | 516.3 | 552.3 | ||||||
Total liabilities and equity | $ | 554.9 | $ | 725.4 | ||||
4
QEP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Period From August 14, 2013, through September 30, 2013 | Period From January 1, 2013, through August 13, 2013 | Nine Months Ended September 30, 2012 | ||||||||||
Successor | Predecessor | Predecessor | ||||||||||
(in millions) | ||||||||||||
OPERATING ACTIVITIES | ||||||||||||
Net income | $ | 7.1 | $ | 41.4 | $ | 56.1 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization | 4.1 | 25.0 | 29.8 | |||||||||
Unit-based compensation expense | 0.1 | — | — | |||||||||
Income from unconsolidated affiliates | — | (3.8 | ) | (5.5 | ) | |||||||
Distributions from unconsolidated affiliates | 0.4 | 4.9 | 6.0 | |||||||||
Amortization of debt issuance costs | 0.1 | — | — | |||||||||
Net loss from asset sales | — | 0.5 | — | |||||||||
Changes in operating assets and liabilities: | ||||||||||||
Accounts receivable | 6.4 | 17.8 | (5.8 | ) | ||||||||
Accounts payable and accrued expenses | (6.0 | ) | 8.9 | (3.0 | ) | |||||||
Other | 2.0 | (3.8 | ) | 4.3 | ||||||||
Net cash provided by operating activities | 14.2 | 90.9 | 81.9 | |||||||||
INVESTING ACTIVITIES | ||||||||||||
Property, plant and equipment | (2.2 | ) | (9.1 | ) | (30.3 | ) | ||||||
Proceeds from sale of assets | — | 0.6 | 0.3 | |||||||||
Net cash used in investing activities | (2.2 | ) | (8.5 | ) | (30.0 | ) | ||||||
FINANCING ACTIVITIES | ||||||||||||
Repayments of long-term debt (to related party) | (95.5 | ) | (66.4 | ) | (34.4 | ) | ||||||
Long-term debt issuance costs | (3.0 | ) | — | — | ||||||||
Net proceeds from initial public offering | 449.6 | — | — | |||||||||
Proceeds from initial public offering distributed to parent | (351.1 | ) | — | — | ||||||||
Contributions from (distributions to) parent, net | 3.0 | (12.2 | ) | (14.1 | ) | |||||||
Distribution to noncontrolling interest | (0.2 | ) | (4.1 | ) | (5.3 | ) | ||||||
Net cash provided by (used in) financing activities | 2.8 | (82.7 | ) | (53.8 | ) | |||||||
Change in cash and cash equivalents | 14.8 | (0.3 | ) | (1.9 | ) | |||||||
Beginning cash and cash equivalents | 1.1 | 1.4 | 2.5 | |||||||||
Ending cash and cash equivalents | $ | 15.9 | $ | 1.1 | $ | 0.6 | ||||||
Supplemental Disclosures: | ||||||||||||
Non-cash investing activities | ||||||||||||
Change in capital expenditure accrual balance | $ | 2.5 | $ | (1.6 | ) | $ | (1.0 | ) | ||||
See notes accompanying the unaudited consolidated financial statements.
5
QEP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)
Successor | ||||||||||||||||||||
Limited Partners | ||||||||||||||||||||
Common Units | Subordinated Units | General Partner Units | Noncontrolling Interest | Total net equity | ||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance at April 19, 2013 (inception - prior to initial public offering) | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Contribution of net assets on August 14, 2013 | 72.2 | 287.3 | 2.2 | 46.1 | 407.8 | |||||||||||||||
Net proceeds from initial public offering | 449.6 | — | — | — | 449.6 | |||||||||||||||
Proceeds from initial public offering distributed to parent | (117.5 | ) | (233.6 | ) | — | — | (351.1 | ) | ||||||||||||
Contributions from parent | 0.4 | 2.6 | — | — | 3.0 | |||||||||||||||
Distribution of noncontrolling interest | — | — | — | (0.2 | ) | (0.2 | ) | |||||||||||||
Amortization of equity-based compensation | 0.1 | — | — | — | 0.1 | |||||||||||||||
Net income for the period from August 14, 2013, through September 30, 2013 | 3.2 | 3.2 | 0.1 | 0.6 | 7.1 | |||||||||||||||
Balance at September 30, 2013 | $ | 408.0 | $ | 59.5 | $ | 2.3 | $ | 46.5 | $ | 516.3 | ||||||||||
See notes accompanying the unaudited consolidated financial statements.
6
QEP MIDSTREAM PARTNERS, LP PREDECESSOR
CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)
Predecessor | ||||||||||||
Parent Net Investment | Noncontrolling Interest | Total Net Equity | ||||||||||
Balance at December 31, 2011 | $ | 451.8 | $ | 50.6 | $ | 502.4 | ||||||
Net income for the nine months ended September 30, 2012 | 53.4 | 2.7 | 56.1 | |||||||||
Contributions from (distributions to) parent, net | (14.1 | ) | — | (14.1 | ) | |||||||
Distribution of noncontrolling interest | — | (5.3 | ) | (5.3 | ) | |||||||
Balance at September 30, 2012 | $ | 491.1 | $ | 48.0 | $ | 539.1 | ||||||
Balance at December 31, 2012 | $ | 504.6 | $ | 47.7 | $ | 552.3 | ||||||
Net income for the period from January 1, 2013, through August 13, 2013 | 38.9 | 2.5 | 41.4 | |||||||||
Distributions to parent, net | (12.2 | ) | — | (12.2 | ) | |||||||
Distribution of noncontrolling interest | — | (4.1 | ) | (4.1 | ) | |||||||
Balance at August 13, 2013 | $ | 531.3 | $ | 46.1 | $ | 577.4 | ||||||
See notes accompanying the unaudited consolidated financial statements.
7
QEP MIDSTREAM PARTNERS, LP
NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 - Description of Business and Basis of Presentation
Description of Business
QEP Midstream Partners, LP (the "Partnership") was formed in Delaware on April 19, 2013, to own, operate, acquire and develop midstream energy assets. The Partnership's assets consist of ownership interests in four gathering systems and two Federal Energy Regulatory Commission ("FERC") regulated pipelines through which we provide natural gas and crude oil gathering and transportation services in Colorado, North Dakota, Utah and Wyoming.
On August 14, 2013, the Partnership completed its initial public offering (the "Offering") of 20,000,000 common units representing limited partner interests in the Partnership. In addition, as of September 4, 2013, the underwriters had exercised their option to purchase an additional 3,000,000 common units (see "Note 3 - Initial Public Offering"). 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 August 14, 2013), refer to QEP Midstream Partners, LP Predecessor (the "Predecessor"). References in this report to "QEP Midstream" the "Partnership," "Successor," "we," "our," "us," or like terms, when used from and after August 14, 2013, in the present tense or prospectively (starting August 14, 2013), refer to QEP Midstream Partners, LP and its subsidiaries. For purposes of these financial statements, "QEP" refers to QEP Resources, Inc. and its consolidated subsidiaries, including the Partnership.
As part of the Offering, QEP Midstream Partners GP, LLC (the "General Partner") and QEP Field Services Company ("Field Services"), both QEP affiliates, collectively contributed to the Partnership (i) a 100% ownership interest in each of QEP Midstream Partners Operating, LLC (the "Operating Company"), QEPM Gathering I, LLC and Rendezvous Pipeline Company, L.L.C. ("Rendezvous Pipeline"), (ii) a 78% interest in Rendezvous Gas Services, L.L.C. ("Rendezvous Gas Services"), and (iii) a 50% equity interest in Three Rivers Gathering, L.L.C. ("Three Rivers Gathering"). The General Partner serves as the general partner of the Partnership and together with QEP provides services to the Partnership pursuant to an omnibus agreement between the parties.
The Predecessor consists of all of the Partnership's gathering assets as well as a 38% equity interest in Uintah Basin Field Services, L.L.C. ("Uintah Basin Field Services") and a 100% interest in all other gathering assets owned by QEP in the Uinta Basin (collectively referred to as the "Uinta Basin Gathering System"). The Uinta Basin Gathering System was retained by QEP and was not part of the assets conveyed to the Partnership.
Basis of Presentation
The interim consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States ("GAAP") and with the instructions for quarterly reports on Form 10-Q and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.
Interim consolidated financial statements are unaudited and do not include all of the information and notes required by GAAP for audited consolidated financial statements. These financial statements should be read in conjunction with the Predecessor's audited consolidated financial statements for the year ended December 31, 2012, included in our Prospectus related to the Offering dated August 8, 2013, (our "Prospectus") as filed with the Securities and Exchange Commission ("SEC"). These financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present the results of operations and financial position. Amounts reported in the Unaudited Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods.
The unaudited consolidated financial statements and accompanying notes prior to the Offering (August 14, 2013) relate to the Predecessor and have been prepared in accordance with GAAP on the basis of QEP's historical ownership of the Predecessor assets. The Predecessor's consolidated financial statements have been prepared from the separate records maintained by QEP and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as parent net investment, in lieu of owner's equity, in the unaudited consolidated financial statements. Further, management does not believe that these financial statements are necessarily comparable to the financial statements reported by the Partnership for periods subsequent to the Offering nor reflective of other transactions that resulted in the capitalization and start-up of the Partnership. See "Item 2 Management's
8
Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting the Comparability of Our Financial Results" within this report 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 Offering.
Note 2 - Summary of Significant Accounting Policies
Investment in Unconsolidated Affiliates
The Partnership and the Predecessor use the equity method to account for investment in unconsolidated affiliates. The investment in unconsolidated affiliates on the Unaudited Consolidated Balance Sheets equals our proportionate share of equity reported by the unconsolidated affiliates. The investment is assessed for possible impairment when events indicate that the fair value of the investment may be below the carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in the determination of net income.
The unconsolidated affiliate of the Partnership and the ownership percentage as of September 30, 2013, was Three Rivers Gathering (50%). The unconsolidated affiliates of the Predecessor and the ownership percentages as of August 13, 2013, and December 31, 2012, were Uintah Basin Field Services (38%) and Three Rivers Gathering (50%), both of which are engaged in the gathering, transportation and compression of natural gas.
Noncontrolling Interests
The Partnership and the Predecessor have a 78% interest in Rendezvous Gas Services, a joint venture with Western Gas Partners, LP ("Western Gas"), which owns a gas gathering system located in Wyoming. Rendezvous Gas Services is consolidated under the voting interest model and Western Gas' non-controlling interest is presented on the Unaudited Consolidated Statements of Income and Unaudited Consolidated Balance Sheets accordingly.
Use of Estimates
The preparation of the consolidated financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. Items subject to estimates and assumptions include the carrying amount of property, plant and equipment, valuation allowances for receivables, valuation of accrued liabilities, accrued revenue and related receivables and obligations related to employee benefits, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Recent Accounting Developments
In December of 2011, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2011-11, Disclosures about Offsetting Assets and Liabilities, which enhances disclosure requirements regarding an entity's financial instruments and derivative instruments that are offset or subject to a master netting arrangement. This information about offsetting and related netting arrangements will enable users of financial statements to understand the effect of those arrangements on the entity's financial position, including the effect of rights of setoff. The amendments were required for annual reporting periods beginning after January 1, 2013, and interim periods within those annual periods. The adoption of this ASU did not have a material effect on our disclosure requirements.
Note 3 - Initial Public Offering
On August 14, 2013, the Partnership completed the Offering of 20,000,000 common units, representing limited partner interests in the Partnership, at a price to the public of $21.00 per common unit. The Partnership received net proceeds of $390.7 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and offering expenses of approximately $29.3 million. Following the Offering, 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, providing additional net proceeds of $58.9 million, after deducting $4.1 million of underwriters' discounts and commissions and structuring fees, to the Partnership.
The Partnership used the net proceeds to repay its outstanding debt balance with QEP, which was assumed with the assets contributed to the Partnership, 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.
9
The following is a reconciliation of proceeds from the Offering (in millions):
Total proceeds from the Offering | $ | 483.0 | ||
Offering costs | (33.4 | ) | ||
Net proceeds from the Offering | 449.6 | |||
Revolving credit facility origination fees | (3.0 | ) | ||
Repayment of outstanding debt with QEP | (95.5 | ) | ||
Net proceeds distributed to QEP from the Offering | $ | 351.1 | ||
As of September 30, 2013, the Partnership's ownership consisted of the following:
Units | % Ownership | |||||
Limited partner common units - QEP | 3,701,750 | 6.8 | % | |||
Limited partner common units - public | 23,003,250 | 42.2 | % | |||
Limited partner subordinated units - QEP | 26,705,000 | 49.0 | % | |||
General partner units | 1,090,000 | 2.0 | % | |||
Total QEP Midstream units | 54,500,000 | |||||
Contribution, Conveyance and Assumption Agreement and Concurrent Transactions
On August 14, 2013, in connection with the closing of the Offering, the Partnership entered into a Contribution, Conveyance and Assumption Agreement (the "Contribution Agreement") with Field Services, the General Partner and the Operating Company. Immediately prior to the closing of the Offering, the following transactions, among others, occurred pursuant to the Contribution Agreement:
• | Field Services contributed to the General Partner, as a capital contribution, a limited liability company interest in the Operating Company with a value equal to 2% of the equity value of the Partnership at the closing of the Offering; |
• | the General Partner contributed to the Partnership, as a capital contribution, the limited liability company interest in the Operating Company in exchange for (a) 1,090,000 general partner units representing the continuation of an aggregate 2% general partner interest in the Partnership and (b) all the incentive distribution rights of the Partnership; |
• | Field Services contributed to the Partnership, as a capital contribution, its remaining limited liability company interests in the Operating Company in exchange for (a) 6,701,750 common units representing a 12.3% limited partner interest in the Partnership, (b) 26,705,000 subordinated units representing a 49% limited partner interest in the Partnership and (c) the right to receive a distribution from the Partnership; and |
• | the public, through the underwriters, contributed $420.0 million in cash (or $390.7 million, net of the underwriters' discounts and commissions, structuring fees and offering expenses of approximately $29.3 million) to the Partnership in exchange for the issuance of 20,000,000 common units. |
Subsequent to the Offering, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units in the Partnership, which reduced Field Services' common unit interest in the Partnership from 12.3% to 6.8%.
The contribution of Field Services' and the General Partner's limited liability company 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, as follows (in millions):
Cash and cash equivalents | $ | 1.1 | ||
Accounts receivable, net | 26.4 | |||
Property, plant and equipment, net | 485.6 | |||
Investment in unconsolidated affiliate | 27.9 | |||
Account payable and accrued expenses | (21.1 | ) | ||
Long-term debt to related party | (95.5 | ) | ||
Asset Retirement Obligation | (11.8 | ) | ||
Other liabilities | (4.8 | ) | ||
Net assets | $ | 407.8 | ||
10
First Amended and Restated Agreement of Limited Partnership of QEP Midstream Partners, LP
On August 14, 2013, in connection with the closing of the Offering, the Agreement of Limited Partnership was amended and restated by the First Amended and Restated Agreement of Limited Partnership of QEP Midstream Partners, LP (as amended and restated, the "Partnership Agreement"). A description of the Partnership Agreement is contained in our Prospectus in the section entitled "Our Partnership Agreement."
Note 4 - Related Party Transactions
The Partnership
The Partnership provides natural gas gathering, compression, treating and transportation services to QEP that result in affiliate transactions. Following the Offering, in addition to the agreements discussed in "Note 3 - Initial Public Offering", the Partnership entered into the following agreements with QEP.
Omnibus Agreement
On August 14, 2013, in connection with the closing of the Offering, the Partnership entered into an Omnibus Agreement (the "Omnibus Agreement") with Field Services, the General Partner, the Operating Company and QEP, which addresses the following matters:
• | the Partnership's payment of an annual amount to QEP, initially in the amount of $13.8 million, for the provision of certain general and administrative services by QEP to the Partnership, including a fixed annual fee of approximately $1.4 million for executive management services provided by certain officers of the General Partner, who are also executives of QEP. The remaining portion of this annual amount reflects an estimate of the costs QEP will incur in providing the services; |
• | the Partnership's obligation to reimburse QEP for any out-of-pocket costs and expenses incurred by QEP in providing general and administrative services (which reimbursement is in addition to certain expenses of the General Partner and its affiliates that are reimbursed under the Partnership's partnership agreement), as well as any other out-of-pocket expenses incurred by QEP on the Partnership's behalf; and |
• | an indemnity by QEP for certain environmental and other liabilities, and the Partnership's obligation to indemnify QEP and its subsidiaries for events and conditions associated with the operation of the Partnership's assets that occur after the closing of the Offering. |
As long as QEP controls the General Partner, the Omnibus Agreement will remain in full force and effect. If QEP ceases to control the General Partner, either party may terminate the Omnibus Agreement, but the indemnification obligations will remain in full force and effect in accordance with their terms.
For the period from August 14, 2013, through September 30, 2013, the Partnership was charged $1.2 million under the Omnibus Agreement by QEP.
Service Agreements
At the closing of the Offering, the Partnership entered into various midstream agreements with QEP including, but not limited to, natural gas, crude oil, water and condensate gathering and transportation agreements, a fixed price condensate purchase agreement, operating agreements and other service agreements. The Partnership believes that the terms and conditions under these agreements are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services in the ordinary course of its business. For the period from August 14, 2013, through September 30, 2013, the Partnership generated approximately 63% of its total revenues under agreements with QEP.
The Predecessor
Prior to the Offering, the Predecessor had the following agreements in place with QEP resulting in affiliate transactions.
Centralized Cash Management
QEP operated a cash management system whereby excess cash from its various subsidiaries, held in separate bank accounts, was consolidated into a centralized account. Sales and purchases related to third-party transactions were settled in cash but were received or paid by QEP within the centralized cash management system.
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Affiliated Debt
The Predecessor's long-term debt consisted of an allocation from Field Services of its total long-term debt related to Field Services' debt agreements with QEP. During the first quarter of 2012, Field Services had a $250.0 million revolving debt agreement (the "2011 Agreement") with QEP for its working capital requirements, in which Field Services was charged a variable interest rate. Interest during the first quarter of 2012 was allocated to the Predecessor based on an interest rate equal to QEP's average borrowing rate, which was 5.2% in the first quarter of 2012. In April 2012, Field Services entered into new debt agreements with QEP replacing the 2011 Agreement with a $250.0 million promissory note, which matured at the end of the first quarter of 2013 with a fixed interest rate of 6.05%. The promissory note was renewed on April 1, 2013, with a maturity date of April 1, 2014. In addition, Field Services entered into a $1.0 billion "revolving credit" type promissory note with QEP, which matures on April 1, 2017, to assist with funding of capital expenditures. Accordingly, all amounts have been classified as "Long-term debt to related party" in our Unaudited Consolidated Balance Sheets. Both agreements require Field Services to pay QEP interest during the last nine months of 2013 at a 6.0% fixed rate. Interest allocated to the Predecessor under these notes in the first quarter of 2013 was based on the fixed-rate due to QEP. Field Services was in compliance with its covenants under the agreements for all periods prior to the Offering, and there are no letters of credit outstanding. At December 31, 2012, allocated debt for the Predecessor was $131.1 million. In connection with the Offering, $95.5 million of affiliated debt was assumed by the Partnership and was repaid in full on August 14, 2013, with proceeds of the Offering extinguishing all affiliated debt of the Partnership.
Allocation of Costs
The employees supporting the Predecessor's operations were employees of QEP. General and administrative expenses allocated to the Predecessor were $3.2 million for the period from July 1, 2013, through August 13, 2013, and $13.6 million for the period from January 1, 2013, through August 13, 2013, and $4.9 million and $12.6 million for the three and nine months ended September 30, 2012, respectively. The consolidated financial statements of the Predecessor include direct charges for operations of our assets and 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. These expenses were charged or allocated to the Predecessor based on the nature of the expenses and its proportionate share of QEP's gross property, plant and equipment, operating income and direct labor costs. Management believes these allocation methodologies were reasonable.
The following table summarizes the related party income statement transactions of the Predecessor with QEP:
Period From July 1, 2013, through August 13, 2013 | Three Months Ended September 30, 2012 | Period From January 1, 2013, through August 13, 2013 | Nine Months Ended September 30, 2012 | |||||||||||||
(in millions) | (in millions) | |||||||||||||||
Revenues from affiliate | $ | 12.1 | $ | 18.6 | $ | 53.4 | $ | 56.2 | ||||||||
Interest expense to affiliate | (0.5 | ) | (1.4 | ) | (2.6 | ) | (5.4 | ) | ||||||||
Note 5 - Property, Plant and Equipment
A summary of the historical cost of the Partnership's and the Predecessor's property, plant and equipment is as follows:
Estimated Useful Lives | September 30, 2013 | December 31, 2012 | ||||||||
Successor | Predecessor | |||||||||
(in millions) | ||||||||||
Gathering equipment | 5 to 40 years | $ | 723.3 | $ | 907.7 | |||||
General support equipment | 3 to 30 years | — | 11.1 | |||||||
Total property, plant and equipment | 723.3 | 918.8 | ||||||||
Accumulated depreciation | (237.0 | ) | (284.7 | ) | ||||||
Total net property, plant and equipment | $ | 486.3 | $ | 634.1 | ||||||
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Note 6 - Asset Retirement Obligations
The Partnership records asset retirement obligations ("ARO") when there are legal obligations associated with the retirement of tangible long-lived assets. The fair values of such costs are estimated by our personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO liability may occur due, among other things, to changes in estimated abandonment costs and estimated settlement timing. The ARO liability is adjusted to present value each period through an accretion calculation using our credit-adjusted, risk-free interest rate.
The following is a reconciliation of the changes in the ARO liability for the periods specified below (in millions):
2013 | |||
Asset Retirement Obligations | |||
Predecessor | |||
ARO liability at January 1, | $ | 16.3 | |
Accretion | 0.7 | ||
ARO liability at August 13, | $ | 17.0 | |
Successor | |||
ARO liability at August 14, | $ | 11.8 | |
Accretion | $ | 0.1 | |
ARO liability at September 30, | $ | 11.9 | |
Note 7 - Debt
On August 14, 2013, in connection with the closing of the Offering, we entered into a $500.0 million senior secured revolving credit facility (the "Credit Facility") with a group of financial institutions. The Credit Facility matures on August 14, 2018 and contains an accordion provision that would allow for the amount of the facility to be increased to $750.0 million with the agreement of the lenders. The Credit Facility is available for working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. Substantially all of the Partnership's assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries, are pledged as collateral under the Credit Facility. In addition, the Credit Facility contains restrictions and events of default customary for agreements of this nature.
Loans under the Credit Facility will bear interest at the Partnership's option at a variable rate per annum equal to either:
• | a base rate, which will be the highest of (i) the administrative agent's prime rate in effect on such day, (ii) the federal funds rate in effect on such day plus 0.50%, and (iii) one-month LIBOR plus 1.0%, in each case, plus an applicable margin ranging from 0.75% to 1.50% based on the Partnership's consolidated leverage ratio; or |
• | LIBOR plus an applicable margin ranging from 1.75% to 2.50% based on the Partnership's consolidated leverage ratio. |
As of September 30, 2013, there was no debt outstanding under the Credit Facility, and the Partnership was in compliance with the covenants under the credit agreement. All debt outstanding prior to and at the Offering relates to intercompany debt with QEP discussed in "Note 4 - Related Party Transactions". The net proceeds from the Offering were used to pay off the $95.5 million of debt assumed by the Partnership in connection with the Offering.
Note 8 - Unit-Based Compensation
In connection with the Offering, the board of directors of the General Partner (the "Board") adopted the QEP Midstream Partners, LP 2013 Long-Term Incentive Plan (the "LTIP") for officers, directors and employees of the General Partner and its affiliates, and any consultants, affiliates of the General Partner or other individuals who perform services for the Partnership. The Partnership reserved 5,341,000 common units for issuance pursuant to and in accordance with the LTIP.
The LTIP provides for the grant, from time to time at the discretion of the Board, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The LTIP limits the number of common units that may be delivered pursuant to awards under the LTIP to 5,341,000 common units.
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Common units cancelled or forfeited will be available for delivery pursuant to other awards. The LTIP is administered by the Board or a designated committee thereof.
Common Units
On August 14, 2013, the Board granted 3,250 common units to the independent director of the Board at $21.00 per unit, which vested immediately. The fair value of common unit awards granted to non-employee directors is based on the fair market value of the Partnership's common units on the date of the grant, and the equity-based compensation expense is recognized at the time of grant, since the common unit awards vest immediately and are non-forfeitable.
Phantom Units
On August 14, 2013, the Board granted 39,500 phantom units with dividend equivalent rights to employees of the General Partner, including executive officers, that vest in equal installments over a three-year period from the grant date. The fair value of phantom unit awards granted to employees is based on the fair market value of the Partnership's common units on the date of the grant, and the equity-based compensation expense is recognized over the vesting period of three years.
The following is a summary of the Partnership's phantom unit award activity for the period ended September 30, 2013:
Phantom Units Outstanding | Weighted-Average Grant-Date Fair Value | ||||||
Unvested balance at beginning of the period | — | $ | — | ||||
Granted | 39,500 | 21.00 | |||||
Vested | — | — | |||||
Forfeited | — | — | |||||
Unvested balance at September 30, 2013 | 39,500 | $ | 21.00 | ||||
Total compensation expense recognized for the common unit and phantom unit awards since the Offering was $0.1 million, and the total amount of unrecognized compensation cost related to the phantom unit award was $0.8 million as of September 30, 2013, which is expected to be recognized over the remaining vesting period of 2.9 years.
Note 9 - Commitments and Contingencies
We are involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of our business. We assess these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in our consolidated financial statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, we may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matter. The Partnership's litigation loss contingencies are discussed below. We are unable to estimate reasonably possible losses in excess of recorded accruals for these contingencies for the reasons set forth above. We believe, however, that the resolution of pending proceedings will not have a material effect on our financial position, results of operations or cash flows.
Litigation
At the closing of the Offering, the assets and agreement subject to the ongoing litigation between Questar Gas Company ("QGC") and Field Services, styled Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah, were assigned to the Partnership. Field Services' former affiliate, QGC, filed this complaint in state court in Utah on May 1, 2012, asserting claims for (i) breach of contract, (ii) breach of implied covenant of good faith and fair dealing, (iii) an accounting and (iv) declaratory judgment related to a 1993 gathering agreement and a 1998 amendment (the "1993 Agreement") executed when the parties were affiliates. Under the 1993 Agreement, certain of our systems provide gathering services to QGC charging an annual gathering rate which is based on cost of service. QGC is disputing the calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. QGC was netting the disputed amount from its monthly payment of the gathering fees to Field Services and has continued to net such amount from its monthly payment to the Partnership. As of September 30, 2013, the Partnership has deferred revenue of $7.0 million related
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to the QGC disputed amount. Specific monetary damages are not asserted. Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement. QGC may seek to amend its complaint to add the Partnership as a defendant in the litigation. The Partnership has been indemnified by QEP for costs, expenses and other losses incurred by the Partnership in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement (defined below in "Note 4 - Related Party Transactions").
Note 10 - Net Income Per Limited Partner Unit
Net income per unit is applicable to the Partnership's limited partner common and subordinated units. Net income per unit is calculated following the two-class method as the Partnership has more than one class of participating securities including common units, subordinated units, general partner units, certain equity-based compensation awards and incentive distribution rights. Net income per unit is calculated by dividing the limited partners' interest in net income attributable to the Partnership, after deducting any General Partner incentive distributions, by the weighted-average number of outstanding common and subordinated units outstanding.
Net income per unit is only calculated for the period subsequent to the Offering as no units were outstanding prior to August 14, 2013. As of September 30, 2013, the basic net income per unit and the diluted net income per unit were equal as there were no potentially dilutive units outstanding.
The following tables set forth distributions in excess of net income attributable to QEP Midstream and the calculation of net income per unit for the period from August 14, 2013, through September 30, 2013 (in millions, except per unit amounts).
Net income attributable to QEP Midstream | $ | 6.5 | ||
General partner's distribution declared(1) | (0.1 | ) | ||
Limited partners' distribution declared on common units(1) | (3.5 | ) | ||
Limited partners' distribution declared on subordinated units(1) | (3.5 | ) | ||
Distribution in excess of net income attributable to QEP Midstream | $ | (0.6 | ) | |
(1) On October 23, 2013, the Partnership declared its first quarterly cash distribution totaling $7.1 million, or $0.13 per unit for the third quarter of 2013 (see "Note 11 - Subsequent Events"). During the period from August 14, 2013, through September 30, 2013, no net income was attributable to incentive distribution rights.
General Partner | Limited Partners' Common Units | Limited Partners' Subordinated Units | Total | |||||||||||||
(in million, except per unit amounts) | ||||||||||||||||
Net income attributable to QEP Midstream: | ||||||||||||||||
Distribution declared | $ | 0.1 | $ | 3.5 | $ | 3.5 | $ | 7.1 | ||||||||
Distributions in excess of net income attributable to QEP Midstream | — | (0.3 | ) | (0.3 | ) | (0.6 | ) | |||||||||
Net income attributable to QEP Midstream | $ | 0.1 | $ | 3.2 | $ | 3.2 | $ | 6.5 | ||||||||
Weighted-average limited partner units outstanding: | ||||||||||||||||
Basic and Diluted | 1.1 | 26.7 | 26.7 | 54.5 | ||||||||||||
Net income per limited partner unit attributable to the QEP Midstream | ||||||||||||||||
Basic and Diluted | $ | 0.12 | $ | 0.12 | ||||||||||||
Note 11 - Subsequent Events
On October 23, 2013, the Partnership declared its first quarterly cash distribution totaling $7.1 million, or $0.13 per unit for the third quarter of 2013. The distribution was calculated based on the Partnership's minimum quarterly distribution of $0.25 per unit, prorated for the period from the date of the Offering, August 14, 2013, to the end of the quarter, September 30, 2013. This distribution will be paid on November 14, 2013, to unitholders of record on the close of business on November 4, 2013. No distributions related to the General Partner's incentive distribution rights were declared.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 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 August 14, 2013, 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.
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 Predecessor's audited consolidated financial statements for the year ended December 31, 2012, included in our Prospectus. 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 Prospectus. See also "Forward-Looking Statements" in Item 3 of this report.
Overview
QEP Midstream Partners, LP (NYSE: QEPM) is a limited partnership recently 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 New York Stock Exchange after the completion of the Offering of 20,000,000 common units, at a price to the public of $21.00 per common unit. Following the Offering, 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 of 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.
Following the Offering, 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 376 miles of natural gas gathering pipelines, 56 miles of crude oil gathering pipelines, 84 miles of water gathering pipelines and a 61-mile, FERC-regulated crude oil pipeline located in the Green River Basin. These assets have a current aggregate natural gas throughput capacity of 737 MMcf/d. |
◦ | Rendezvous Gas. Rendezvous Gas is a joint venture between QEP and 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 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's Blacks Fork processing complex in southwest Wyoming to an interconnect with the Kern River Pipeline. Rendezvous Pipeline has total throughput capacity of 460 MMcf/d. |
• | 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 518 miles of low-pressure, gas gathering pipelines and 23,197 bhp of gas compression. The Vermillion Gathering System has combined total throughput capacity of 206 MMcf/d. |
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• | Three Rivers Gathering System. Three Rivers Gathering is a joint venture between QEP and Ute Energy Midstream Holdings, LLC that was formed to transport natural gas gathered by Uintah Basin Field Services, an indirectly owned subsidiary in which QEP owns a 38% interest, and other third-party volumes to gas processing facilities owned by QEP 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. |
• | 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 15 miles of gas gathering pipelines, 15 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. |
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 all other gathering assets that QEP owns in the Uinta Basin Gathering System. These assets were retained by QEP and were not part of the assets conveyed to the Partnership in connection with the Offering.
The Results of Operations discussed below include historical information that relates to operations prior to the date of the Offering, August 14, 2013, which represents our Predecessor and includes combined results for both the properties conveyed to the Partnership in connection with the Offering and the properties retained by our Predecessor. Under "Supplemental Disclosures" below, we have included historical data limited to only the properties conveyed to us in connection with the Offering, as we believe such data is more useful to the reader to better understand trends in our operations.
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. In addition to our fee-based gathering services, for the period from August 14, 2013, through September 30, 2013, approximately 1% 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. Please read "Item 3. Quantitative and Qualitative Disclosures About Market Risk" below for a discussion of our exposure to commodity price risk through our condensate recovery and sales.
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, Vermillion 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 payments to cover any shortfall. For a discussion regarding our minimum volume commitments, please read "Business — Our Assets and Operations — Minimum Volume Commitments" within our Prospectus.
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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 ("NGLs"), 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 expenditures on our gathering systems throughout the calendar year to avoid significant variability in our cash flows and maintain safe operations. There is some seasonality in our expenditures as we generally do less 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 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 and deferred revenue associated with minimum volume commitment payments. 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.
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 flow from operating activities, respectively. Adjusted EBITDA and distributable cash flow should not be considered an alternative to net income
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attributable to the Partnership or the Predecessor, net cash flow from 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 flow from 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. For a reconciliation of Adjusted EBITDA and distributable cash flow to net income attributable to the Partnership or the Predecessor and net cash flows provided by operating activities, please see "Results of Operations" below.
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. During 2012, QEP operated six drilling rigs in the Pinedale Field, but in 2013 QEP reduced the number of operated rigs to four. Although the rig count is currently lower than the rig count in 2012, QEP has stated that it expects to complete approximately the same number of wells for the year ended December 31, 2013, as it did for the year ended December 31, 2012, as a result of the inventory of wells drilled but not yet completed at the beginning of the year and more efficient drilling and completion operations. We expect a slight decline in production from the Pinedale Field resulting from the reduced rig count. Please read "Cash Distribution Policy and Restrictions on Distributions — Assumptions and Considerations" within our Prospectus.
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.
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 has established pipeline integrity management programs that 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 have increased 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. For more information see "Business — Regulation of the Industry and Our Operations as to Rates and Terms and Conditions of Service" included in our Prospectus.
20
Acquisition opportunities
We may acquire additional midstream energy assets from QEP or third parties. If QEP chooses to pursue midstream asset sales, it is under no contractual obligation to offer assets or business opportunities to us. We are not currently a party to any written or unwritten agreements to purchase additional midstream assets from QEP and we do not know when QEP will offer to sell us additional assets, if at all. 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 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 Offering 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 Offering include revenues and expenses relating to QEP's ownership of the Uinta Basin Gathering System and general support equipment. These assets were retained by QEP and were not contributed to the Partnership in connection with the Offering.
General and administrative expenses
For the period from July 1, 2013, through August 13, 2013, the Predecessor incurred $3.2 million and for the period from January 1, 2013, through August 13, 2013, the Predecessor incurred $13.6 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.
Subsequent to the Offering, QEP charges the Partnership a combination of direct and allocated charges for administrative and operational services in accordance with the Omnibus Agreement. For the period from August 14, 2013, through September 30, 2013, the Partnership incurred $1.5 million of such administrative and operational services expenses, of which $1.2 million was charged by QEP as an administrative fee.
We anticipate incurring approximately $2.5 million of incremental general and administrative expenses annually 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 Offering. The Partnership's general and administrative expense will also include compensation expense associated with the QEP Midstream Partners, LP 2013 Long-Term Incentive Plan.
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. Subsequent to the Offering, all affiliate and third-party transactions are funded by our working capital. This will impact the comparability of our cash flow statements, working capital analysis and liquidity discussion.
21
Interest expense
Prior to the Offering, we incurred interest expense on intercompany notes payable to QEP that was allocated to us. These balances were repaid with a portion of the proceeds from the Offering; therefore, interest expense attributable to these balances and reflected in our historical consolidated financial statements will not be incurred in the future. Upon the closing of the Offering, we entered into a $500.0 million revolving credit facility agreement, which provides for customary short-term interest rates. See "Results of Operations - Liquidity and Capital Resources - Credit Facility" below.
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.
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Results of Operations
Period From August 14, 2013, through September 30, 2013 | Period From July 1, 2013, through August 13, 2013 | Three Months Ended September 30, 2012 | Period From August 14, 2013, through September 30, 2013 | Period From January 1, 2013, through August 13, 2013 | Nine Months Ended September 30, 2012 | |||||||||||||||||||
Successor | Predecessor | Predecessor | Successor | Predecessor | Predecessor | |||||||||||||||||||
(in millions, except operating and per unit amounts) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Gathering and transportation | $ | 16.2 | $ | 19.2 | $ | 39.4 | $ | 16.2 | $ | 92.9 | $ | 113.4 | ||||||||||||
Condensate sales | 0.2 | 0.9 | 1.4 | 0.2 | 7.4 | 9.0 | ||||||||||||||||||
Total revenues | 16.4 | 20.1 | 40.8 | 16.4 | 100.3 | 122.4 | ||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||
Gathering expenses | 3.1 | 3.7 | 7.7 | 3.1 | 19.7 | 21.6 | ||||||||||||||||||
General and administrative | 1.5 | 3.2 | 4.9 | 1.5 | 13.6 | 12.6 | ||||||||||||||||||
Taxes other than income taxes | 0.3 | 0.4 | 0.8 | 0.3 | 1.3 | 2.4 | ||||||||||||||||||
Depreciation and amortization | 4.1 | 4.9 | 10.1 | 4.1 | 25.0 | 29.8 | ||||||||||||||||||
Total operating expenses | 9.0 | 12.2 | 23.5 | 9.0 | 59.6 | 66.4 | ||||||||||||||||||
Net loss from property sales | — | (0.1 | ) | — | — | (0.5 | ) | — | ||||||||||||||||
Operating income | 7.4 | 7.8 | 17.3 | 7.4 | 40.2 | 56.0 | ||||||||||||||||||
Income from unconsolidated affiliates | — | 0.4 | 2.3 | — | 3.8 | 5.5 | ||||||||||||||||||
Interest expense | (0.3 | ) | (0.5 | ) | (1.4 | ) | (0.3 | ) | (2.6 | ) | (5.4 | ) | ||||||||||||
Net income | 7.1 | 7.7 | 18.2 | 7.1 | 41.4 | 56.1 | ||||||||||||||||||
Net income attributable to noncontrolling interest | (0.6 | ) | (0.6 | ) | (1.0 | ) | (0.6 | ) | (2.5 | ) | (2.7 | ) | ||||||||||||
Net income attributable to QEP Midstream or Predecessor | $ | 6.5 | $ | 7.1 | $ | 17.2 | $ | 6.5 | $ | 38.9 | $ | 53.4 | ||||||||||||
Operating Statistics | ||||||||||||||||||||||||
Natural gas throughput in millions of MMBtu | ||||||||||||||||||||||||
Gathering and transportation | 40.8 | 45.9 | 101.4 | 40.8 | 230.9 | 293.9 | ||||||||||||||||||
Equity interest(1) | 2.5 | 2.8 | 7.0 | 2.5 | 13.4 | 21.3 | ||||||||||||||||||
Total natural gas throughput | 43.3 | 48.7 | 108.4 | 43.3 | 244.3 | 315.2 | ||||||||||||||||||
Throughput attributable to noncontrolling interests(2) | (0.8 | ) | (1.4 | ) | (3.1 | ) | (0.8 | ) | (6.7 | ) | (10.1 | ) | ||||||||||||
Total throughput attributable to QEP Midstream or Predecessor | 42.5 | 47.3 | 105.3 | 42.5 | 237.6 | 305.1 | ||||||||||||||||||
Crude oil and condensate gathering system throughput volumes (in MBbls) | 670.3 | 583.4 | 1,399.7 | 670.3 | 3,243.1 | 4,131.0 | ||||||||||||||||||
Water gathering volumes (in MBbls) | 538.4 | 552.6 | 1,076.5 | 538.4 | 2,450.3 | 2,928.5 | ||||||||||||||||||
Condensate sales volumes (in MBbls) | 2.2 | 11.7 | 17.3 | 2.2 | 90.6 | 102.8 | ||||||||||||||||||
Price | ||||||||||||||||||||||||
Average gas gathering and transportation fee (per MMBtu) | $ | 0.34 | $ | 0.37 | $ | 0.34 | $ | 0.34 | $ | 0.35 | $ | 0.34 | ||||||||||||
Average oil and condensate gathering fee (per barrel) | $ | 2.34 | $ | 2.37 | $ | 2.14 | $ | 2.34 | $ | 2.44 | $ | 2.29 | ||||||||||||
Average water gathering fee (per barrel) | $ | 1.85 | $ | 1.83 | $ | 1.83 | $ | 1.85 | $ | 1.82 | $ | 1.84 | ||||||||||||
Average condensate sale price (per barrel) | $ | 85.25 | $ | 78.79 | $ | 84.93 | $ | 85.25 | $ | 81.63 | $ | 87.87 | ||||||||||||
Non-GAAP Measures | ||||||||||||||||||||||||
Adjusted EBITDA | $ | 10.5 | $ | 12.3 | $ | 28.0 | $ | 10.5 | $ | 65.4 | $ | 86.5 | ||||||||||||
(1) | Includes our 50% share of gross volumes from Three Rivers Gathering and our 38% share of gross volumes from Uintah Basin Field Services. |
(2) | Includes the 22% noncontrolling interest in Rendezvous Gas. |
23
Successor Results of Operations
On August 14, 2013, the Partnership completed the Offering. Prior to the closing of the Offering, 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 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, which was retained by QEP. The Partnership’s (Successor’s) operating results for the period from August 14, 2013, through September 30, 2013 are presented below.
Period From August 14, 2013, through September 30, 2013
Revenue
Gathering and transportation. Gathering and transportation revenues were $16.2 million for the period from August 14, 2013, through September 30, 2013. Natural gas gathering and transportation revenue was $13.7 million with throughput of 42.5 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 30.9 million MMBtu as a result of increased production at QEP's Pinedale operations and our Vermillion Gathering System with throughput of 6.1 million MMBtu.
Crude oil and condensate revenue was $1.5 million for the period from August 14, 2013, through September 30, 2013, as a result of an average gathering fee of $2.34 per bbl and throughput of 670.3 Mbbls of which 514.9 Mbbls was attributable to our Green River Gathering System and 155.4 Mbbls was attributable to our North Dakota Gathering System. Water gathering revenue consisted of $1.0 million for the period from August 14, 2013, through September 30, 2013, from throughput of 538.4 Mbbls and an average fee of $1.85 per bbl at our Green River Gathering System.
Condensate sales. Revenue from condensate sales was $0.2 million for the period from August 14, 2013, through September 30, 2013, from sales volumes of 2.2 Mbbls at a price of $85.25 per bbl as a result of our fixed price sales agreement with QEP, which was effective on August 14, 2013.
Operating Expenses
Gathering expenses. Gathering expenses were $3.1 million for the period from August 14, 2013, through September 30, 2013, of which the majority of the expenses were incurred on our Green River and Vermillion Gathering Systems.
General and administrative. General and administrative expenses were $1.5 million for the period from August 14, 2013, through September 30, 2013, consisting of $1.2 million from charges under the Omnibus Agreement, $0.1 million for unit-based compensation expense and the remainder related to other expenses related to operating as a publicly traded partnership.
Taxes other than income taxes. Taxes other than income taxes were $0.3 million for the period from August 14, 2013, through September 30, 2013, primarily attributable to property tax accruals on our gathering systems.
Depreciation and amortization. Depreciation and amortization expenses were $4.1 million for the period from August 14, 2013, through September 30, 2013.
Other Results Below Operating Income
Interest expense. Interest expense was $0.3 million for the period from August 14, 2013, through September 30, 2013, related to commitment fees paid on the unused portion of the Credit Facility. There were no borrowings under the Credit Facility during the period.
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Predecessor Results of Operations
The Predecessor financial statements were prepared in connection with the Offering. The Predecessor consists of all of the Partnership’s gathering assets as well as the Uinta Basin Gathering System. The Uinta Basin Gathering System was retained by QEP and was not part of the assets conveyed to the Partnership.
Period From July 1, 2013, through August 13, 2013 - Predecessor
Revenue
Gathering and transportation. Gathering and transportation revenues were $19.2 million for the period from July 1, 2013, through August 13, 2013. Natural gas gathering and transportation revenue was $16.8 million with throughput of 47.3 million MMBtu and an average gas gathering and transportation fee of $0.37 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 25.4 million MMBtu of throughput as a result of increased production at QEP's Pinedale operations; the Predecessor's Unita Basin Gathering System, with throughput of 8.9 million MMBtu; and our Vermillion Gathering System, with throughput of 5.1 million MMBtu.
Crude oil and condensate revenue was $1.4 million for the period from July 1, 2013, through August 13, 2013, as a result of an average gathering fee of $2.37 per bbl and throughput of 583.4 Mbbls of which 462.6 Mbbls was attributable to our Green River Gathering System and 120.8 Mbbls was attributable to our North Dakota Gathering System. Water gathering revenue consisted of $1.0 million for the period from July 1, 2013, through August 13, 2013, from throughput of 552.6 Mbbls and an average fee of $1.83 per bbl at our Green River Gathering System.
Condensate sales. Revenue from condensate sales was $0.9 million for the period from July 1, 2013, through August 13, 2013, from sales volumes of 11.7 Mbbls at a price of $78.79 per bbl primarily attributable to our Green River Gathering System.
Operating Expenses
Gathering expenses. Gathering expenses were $3.7 million for the period from July 1, 2013, through August 13, 2013, of which the majority of the expenses were incurred on the Predecessor's Green River, Unita Basin and Vermillion Gathering Systems.
General and administrative. General and administrative expenses were 3.2 million for the period from July 1, 2013, through August 13, 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 $0.4 million for the period from July 1, 2013, through August 13, 2013, primarily attributable to property tax accruals.
Depreciation and amortization. Depreciation and amortization expenses were $4.9 million for the period from July 1, 2013, through August 13, 2013.
Other Results Below Operating Income
Income from unconsolidated affiliates. Income from unconsolidated affiliates was $0.4 million for the period from July 1, 2013, through August 13, 2013. Income from Uintah Basin Field Services was $0.3 million and income from Three Rivers Gathering was $0.1 million.
Interest expense. Interest expense was $0.5 million for the period from July 1, 2013, through August 13, 2013, related to interest charged on the Predecessor's outstanding long-term debt with QEP throughout the period.
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Three Months Ended September 30, 2012 - Predecessor
Revenue
Gathering and transportation. Gathering and transportation revenues were $39.4 million for the three months ended September 30, 2012. Natural gas gathering and transportation revenue was $34.4 million with throughput of 105.3 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 54.5 million MMBtu of throughput; the Predecessor's Unita Basin Gathering System, with throughput of 20.1 million MMBtu; and our Vermillion Gathering System, with throughput of 12.7 million MMBtu.
Crude oil and condensate revenue was $3.0 million for the three months ended September 30, 2012, as a result of an average gathering fee of $2.14 per bbl and throughput of 1,399.7 Mbbls, of which 1,114.4 Mbbls was attributable to our Green River Gathering System and 285.3 Mbbls was attributable to our North Dakota Gathering System. Water gathering revenue consisted of $2.0 million for the three months ended September 30, 2012, from throughput of 1,076.5 Mbbls and an average fee of $1.83 per bbl at our Green River Gathering System.
Condensate sales. Revenue from condensate sales was $1.4 million for the three months ended September 30, 2012, from sales volumes of 17.3 Mbbls at a price of $84.93 per bbl primarily attributable to our Green River Gathering System.
Operating Expenses
Gathering expenses. Gathering expenses were $7.7 million for the three months ended September 30, 2012, of which the majority of the expenses were incurred on the Predecessor's Green River, Unita Basin and Vermillion Gathering Systems.
General and administrative. General and administrative expenses were $4.9 million for the three months ended September 30, 2012, 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 $0.8 million for the three months ended September 30, 2012, primarily attributable to property tax accruals on our gathering systems partially offset by a property tax refund received during the third quarter of 2012 related to our Vermillion Gathering System.
Depreciation and amortization. Depreciation and amortization expenses were $10.1 million for the three months ended September 30, 2012, related to normal depreciation and accretion expenses recognized on the gathering systems in place.
Other Results Below Operating Income
Income from unconsolidated affiliates. Income from unconsolidated affiliates was $2.3 million for the three months ended September 30, 2012. Income from Uintah Basin Field Services was $1.7 million and income from Three Rivers Gathering was $0.6 million.
Interest expense. Interest expense was $1.4 million for the three months ended September 30, 2012, related to interest charged on the Predecessor's outstanding long-term debt with QEP throughout the period.
Period From January 1, 2013, through August 13, 2013 - Predecessor
Revenue
Gathering and transportation. Gathering and transportation revenues were $92.9 million for the period from January 1, 2013, through August 13, 2013. Natural gas gathering and transportation revenue was $80.8 million with throughput of 237.6 million MMBtu and an average gas gathering and transportation fee of $0.35 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 124.0 million MMBtu of throughput as a result of increased production at QEP's Pinedale operations; the Predecessor's Unita Basin Gathering System, with throughput of 45.8 million MMBtu; and our Vermillion Gathering System, with throughput of 30.2 million MMBtu.
26
Crude oil and condensate revenue was $7.9 million for the period from January 1, 2013, through August 13, 2013, as a result of an average gathering fee of $2.44 per bbl and throughput of 3,243.1 Mbbls of which 2,490.0 Mbbls was attributable to our Green River Gathering System and 753.1 Mbbls was attributable to our North Dakota Gathering System. Water gathering revenue consisted of $4.5 million for the period from January 1, 2013, through August 13, 2013, from throughput of 2,450.3 Mbbls and an average fee of $1.82 per bbl at our Green River Gathering System.
Condensate sales. Revenue from condensate sales was 7.4 million for the period from January 1, 2013, through August 13, 2013, from sales volumes of 90.6 Mbbls at a price of $81.63 per bbl primarily attributable to the Predecessor's Green River, Unita Basin and Vermillion Gathering Systems.
Operating Expenses
Gathering expenses. Gathering expenses were $19.7 million for the period from January 1, 2013, through August 13, 2013, of which the majority of the expenses were incurred on the Predecessor's Green River, Unita Basin and Vermillion Gathering Systems.
General and administrative. General and administrative expenses were $13.6 million for the period from January 1, 2013, through August 13, 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 $1.3 million for the period from January 1, 2013, through August 13, 2013, primarily attributable to property tax accruals on our gathering systems.
Depreciation and amortization. Depreciation and amortization expenses were $25.0 million for the period from January 1, 2013, through August 13, 2013.
Other Results Below Operating Income
Income from unconsolidated affiliates. Income from unconsolidated affiliates was $3.8 million for the period from January 1, 2013, through August 13, 2013. Income from Uintah Basin Field Services was $2.2 million and income from Three Rivers Gathering was $1.6 million.
Interest expense. Interest expense was $2.6 million for the period from January 1, 2013, through August 13, 2013, related to interest charged on the Predecessor's outstanding long-term debt with QEP throughout the period.
Nine Months Ended September 30, 2012 - Predecessor
Revenue
Gathering and transportation. Gathering and transportation revenues were $113.4 million for the nine months ended September 30, 2012. Natural gas gathering and transportation revenue was $98.5 million with throughput of 305.1 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 149.4 million MMBtu of throughput; the Predecessor's Unita Basin Gathering System, with throughput of 59.4 million MMBtu; and our Vermillion Gathering System, with throughput of 38.9 million MMBtu.
Crude oil and condensate revenue was $9.5 million for the nine months ended September 30, 2012, as a result of an average gathering fee of $2.29 per bbl and throughput of 4,131.0 Mbbls of which 3,362.7 Mbbls was attributable to our Green River Gathering System and 768.3 Mbbls was attributable to our North Dakota Gathering System. Water gathering revenue consisted of $5.4 million for the nine months ended September 30, 2012, from throughput of 2,928.5 Mbbls and an average fee of $1.84 per bbl at our Green River Gathering System.
Condensate sales. Revenue from condensate sales was $9.0 million for the nine months ended September 30, 2012, from sales volumes of 102.8 Mbbls at a price of $87.87 per bbl primarily attributable to our Green River Gathering System.
Operating Expenses
Gathering expenses. Gathering expenses were $21.6 million for the nine months ended September 30, 2012, of which the majority of the expenses were incurred on the Predecessor's Green River, Unita Basin and Vermillion Gathering Systems.
27
General and administrative. General and administrative expenses were $12.6 million for the nine months ended September 30, 2012, 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 $2.4 million for the nine months ended September 30, 2012, primarily attributable to property tax accruals on our gathering systems.
Depreciation and amortization. Depreciation and amortization expenses were $29.8 million for the nine months ended September 30, 2012, related to normal depreciation and accretion expenses recognized on the gathering systems in place.
Other Results Below Operating Income
Income from unconsolidated affiliates. Income from unconsolidated affiliates was $5.5 million for the nine months ended September 30, 2012. Income from Uintah Basin Field Services was $3.0 million and income from Three Rivers Gathering was $2.5 million.
Interest expense. Interest expense was $5.4 million for the nine months ended September 30, 2012, related to interest charged on the Predecessor's outstanding long-term debt with QEP throughout the period.
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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 and deferred revenue associated with minimum volume commitment payments. 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 flow from operating activities. The following table presents a reconciliation of Adjusted EBITDA and distributable cash flow to net income attributable to the Partnership or the Predecessor, as applicable, and net cash flow from operating activities for each of the periods indicated.
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||
September 30, 2013 | September 30, 2013 | |||||||||||||||||||||||
Period From August 14, 2013, through September 30, 2013 | Period From July 1, 2013, through August 13, 2013 | Three Months Ended September 30, 2012 | Period From August 14, 2013, through September 30, 2013 | Period From January 1, 2013, through August 13, 2013 | Nine Months Ended September 30, 2012 | |||||||||||||||||||
Successor | Predecessor | Predecessor | Successor | Predecessor | Predecessor | |||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Unaudited Reconciliation of Net Income Attributable to QEP Midstream or Predecessor to Adjusted EBITDA and Distributable Cash Flows | ||||||||||||||||||||||||
Net income attributable to QEP Midstream or Predecessor | $ | 6.5 | $ | 7.1 | $ | 17.2 | $ | 6.5 | $ | 38.9 | $ | 53.4 | ||||||||||||
Interest expense | 0.3 | 0.5 | 1.4 | 0.3 | 2.6 | 5.4 | ||||||||||||||||||
Depreciation and amortization | 4.1 | 4.9 | 10.1 | 4.1 | 25.0 | 29.8 | ||||||||||||||||||
Noncontrolling interest share of depreciation and amortization(1) | (0.4 | ) | (0.3 | ) | (0.7 | ) | (0.4 | ) | (1.6 | ) | (2.1 | ) | ||||||||||||
Net loss from asset sales | — | 0.1 | — | — | 0.5 | — | ||||||||||||||||||
Adjusted EBITDA | $ | 10.5 | $ | 12.3 | $ | 28.0 | $ | 10.5 | $ | 65.4 | $ | 86.5 | ||||||||||||
Cash interest paid | (0.2 | ) | (0.2 | ) | ||||||||||||||||||||
Maintenance capital expenditures | (4.3 | ) | (4.3 | ) | ||||||||||||||||||||
Reimbursements for maintenance capital expenditures | 3.0 | 3.0 | ||||||||||||||||||||||
Cash adjustments for non-controlling interest and equity method investments | 0.6 | 0.6 | ||||||||||||||||||||||
Distributable Cash Flow | $ | 9.6 | $ | 9.6 | ||||||||||||||||||||
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Nine Months Ended | ||||||||||||||||||
September 30, 2013 | ||||||||||||||||||
Period From August 14, 2013, through September 30, 2013 | Period From January 1, 2013, through August 13, 2013 | Nine Months Ended September 30, 2012 | ||||||||||||||||
Successor | Predecessor | Predecessor | ||||||||||||||||
(in millions) | ||||||||||||||||||
Reconciliation of Net Cash Flows Provided by Operating Activities to Adjusted EBITDA and Distributable Cash Flows | ||||||||||||||||||
Net cash provided by operating activities | $ | 14.2 | $ | 90.9 | $ | 81.9 | ||||||||||||
Noncontrolling interest share of depreciation and amortization(1) | (0.4 | ) | (1.6 | ) | (2.1 | ) | ||||||||||||
Income from unconsolidated affiliates, net of distributions from unconsolidated affiliates | (0.4 | ) | (1.1 | ) | (0.5 | ) | ||||||||||||
Net income attributable to noncontrolling interest | (0.6 | ) | (2.5 | ) | (2.7 | ) | ||||||||||||
Interest expense | 0.3 | 2.6 | 5.4 | |||||||||||||||
Working capital changes | (2.4 | ) | (22.9 | ) | 4.5 | |||||||||||||
Amortization of deferred financing charges | (0.1 | ) | — | — | ||||||||||||||
Unit-based compensation expense | (0.1 | ) | — | — | ||||||||||||||
Adjusted EBITDA | $ | 10.5 | $ | 65.4 | $ | 86.5 | ||||||||||||
Cash interest paid | (0.2 | ) | ||||||||||||||||
Maintenance capital expenditures | (4.3 | ) | ||||||||||||||||
Reimbursements for maintenance capital expenditures | 3.0 | |||||||||||||||||
Cash adjustments for non-controlling interest and equity method investments | 0.6 | |||||||||||||||||
Distributable Cash Flow | $ | 9.6 | ||||||||||||||||
(1) | Represents the noncontrolling interest's 22% share of depreciation and amortization attributable to Rendezvous Gas Services. |
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Liquidity and Capital Resources
Historically, our sources of liquidity included cash generated from operations and funding from QEP. We historically participated in QEP's centralized cash management program under which the net balance of our cash receipts and cash disbursements were settled with QEP on a periodic basis. Following the Offering, the we maintain our own bank accounts and sources of liquidity and continue to utilize QEP's cash management expertise.
Our ongoing sources of liquidity following the Offering include cash generated from operations, borrowings under our revolving credit facility, and issuances of additional debt and equity securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.
Cash Flow
The following table and discussion presents a summary of our net cash provided by operating activities, investing activities and financing activities for the periods indicated.
Period From August 14, 2013, through September 30, 2013 | Period From January 1, 2013, through August 13, 2013 | Nine Months Ended September 30, 2012 | ||||||||||
Successor | Predecessor | Predecessor | ||||||||||
(in millions) | ||||||||||||
Net cash provided by (used in): | ||||||||||||
Operating activities | $ | 14.2 | $ | 90.9 | $ | 81.9 | ||||||
Investing activities | (2.2 | ) | (8.5 | ) | (30.0 | ) | ||||||
Financing activities | 2.8 | (82.7 | ) | (53.8 | ) | |||||||
Operating Activities. The primary components of net cash provided from operating activities are changes in working capital, non-cash adjustments to net income and net income and are presented in the following table:
Period From August 14, 2013, through September 30, 2013 | Period From January 1, 2013, through August 13, 2013 | Nine Months Ended September 30, 2012 | ||||||||||
Successor | Predecessor | Predecessor | ||||||||||
(in millions) | ||||||||||||
Net income | $ | 7.1 | $ | 41.4 | $ | 56.1 | ||||||
Non-cash adjustments to net income | 4.7 | 26.6 | 30.3 | |||||||||
Changes in operating assets and liabilities | 2.4 | 22.9 | (4.5 | ) | ||||||||
Net cash provided from operating activities | $ | 14.2 | $ | 90.9 | $ | 81.9 | ||||||
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Investing Activities. Our Predecessor's historical capital expenditures were funded from a combination of cash flow generated from operations and funding from QEP. The Partnership's capital expenditures were funded from cash flow generated from operations, and issuances of additional debt and equity securities. Our historical capital expenditures are presented in the following table:
Period From August 14, 2013, through September 30, 2013 | Period From January 1, 2013, through August 13, 2013 | Nine Months Ended September 30, 2012 | ||||||||||
Successor | Predecessor | Predecessor | ||||||||||
(in millions) | ||||||||||||
Total accrual capital expenditures | $ | 4.7 | $ | 7.5 | $ | 29.3 | ||||||
Change in accruals and non-cash items | (2.5 | ) | 1.6 | 1.0 | ||||||||
Total cash capital expenditures | $ | 2.2 | $ | 9.1 | $ | 30.3 | ||||||
Financing Activities. As a result of the Offering, for the period from August 14, 2013, through September 30, 2013, we had net proceeds of $449.6 million which were used to repay long-term debt to QEP debt of $95.5 million, pay revolving credit origination fees of $3.0 million and make a cash distribution to QEP for $351.1 million. Additionally, the Partnership received $3.0 million from QEP under the indemnification provisions of the Omnibus Agreement for capital expenditures incurred by the Partnership for a pipeline repair project.
For the period from January 1, 2013, through August 13, 2013, the Predecessor's cash used in financing activities primarily consisted of $66.4 million in repayments of long-term debt to QEP compared to $34.4 million of cash used in financing activities of the Predecessor in the first nine months of 2012. In addition, our Predecessor made distributions to QEP of $12.2 million and distributions to its noncontrolling interest in Rendezvous Gas of $4.1 million for the period from January 1, 2013, through August 13, 2013.
Capital Requirements
The crude oil and natural gas gathering segment of the midstream energy business is capital-intensive, requiring investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement requires that we categorize our capital expenditures as either maintenance or expansion.
• | Maintenance capital expenditures are those cash expenditures that will enable us to maintain our operating capacity or operating income over the long term. Maintenance capital expenditures include well connections or the replacement, improvement or expansion of existing capital assets, including the construction or development of new capital assets, to replace expected reductions in hydrocarbons available for gathering handled by our gathering systems. Other examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines and compression equipment and to maintain equipment reliability, integrity and safety, as well as to address environmental laws and regulations. |
• | Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity or operating income over the long-term. Expansion capital expenditures include the acquisition of assets from QEP or third parties and the construction or development of additional pipeline capacity, well connections or compression, to the extent such expenditures are expected to expand our long-term operating capacity or operating income. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is disposed of or abandoned. |
We expect our gross capital expenditures for the year ending December 31, 2013, to be $24.5 million of which $21.5 million relates to maintenance capital expenditures and the remaining $3.0 million for expansion capital. Of the $21.5 million maintenance capital, we expect to incur $9.4 million for new well connections, $3.0 million for compressor repairs and overhauls, $7.0 million for gathering system projects, and the remaining $2.1 million for various other projects. The expansion capital of $3.0 million will be spent for compressor replacement projects. We expect to receive $5.0 million reimbursement from QEP under the indemnification provisions of the Omnibus Agreement for capital expenditures incurred by the Partnership for a pipeline repair project. Our future expansion capital expenditures may vary significantly from period to period based on
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the investment opportunities available to us. We expect to fund future capital expenditures from cash flow generated from our operations, borrowings under our Credit Facility, the issuance of additional partnership units or debt offerings.
Distributions
We will pay a minimum quarterly distribution of $0.25 per unit, which equates to $13.6 million per quarter, or $54.5 million per year, based on the number of common, subordinated and general partner units outstanding. Although our partnership agreement requires that we distribute all of our available cash each quarter, we do not have a legal obligation to distribute any particular amount per common unit. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions" within our Prospectus.
On October 23, 2013, the Partnership declared its first quarterly cash distribution totaling $7.1 million, or $0.13 per unit for the third quarter of 2013. The distribution was calculated based on our minimum quarterly distribution of $0.25 per unit, prorated for the period from the date of the Offering, August 14, 2013, to the end of the quarter, September 30, 2013. This distribution will be paid on November 14, 2013, to unitholders of record on the close of business on November 4, 2013. No distributions related to the General Partner's incentive distribution rights were declared.
Credit Facility
On August 14, 2013, in connection with the closing of the Offering, we entered into the Credit Facility, a $500.0 million senior secured revolving credit agreement, with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders with a maturity date of August 14, 2018. The Credit Facility is available for working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. Substantially all of the Partnership's assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries and other customary exclusions, are pledged as collateral under the Credit Facility. In addition, the Credit Facility contains restrictions and events of default customary for transactions of this nature.
The Credit Facility contains various covenants and restrictive provisions and also requires maintenance of a total leverage ratio of not more than 5.00 to 1.00 (or, after the consummation of a qualified senior notes offering, not more than 5.50 to 1.00), an interest coverage ratio of not less than 2.50 to 1.00 and after consummation of a qualified senior notes offering, a senior secured leverage ratio of not more than 3.50 to 1.00.
Loans under the Credit Facility (other than swing line loans discussed below) will bear interest at the Partnership's option at a variable rate per annum equal to either:
• | a base rate, which will be the highest of (i) the administrative agent’s prime rate in effect on such day, (ii) the federal funds rate in effect on such day plus 0.50%, and (iii) one-month LIBOR plus 1.0%, in each case, plus an applicable margin ranging from 0.75% to 1.50% based on the Partnership's consolidated leverage ratio; or |
• | LIBOR plus an applicable margin ranging from 1.75% to 2.50% based on the Partnership's consolidated leverage ratio. |
• | Swing line loans will bear interest at (i) the federal funds rate plus an applicable margin ranging from 0.75% to 1.50% based on the Partnership's consolidate leverage ratio or (ii) a rate to be established as provided in the Credit Facility, as selected by the borrower and specified in the swing line loan notice delivered by the borrower in connection with the loan. |
There were no borrowings under the Credit Facility during the period ended September 30, 2013. The unused portion of the Credit Facility is subject to a commitment fee ranging from 0.325% to 0.500% per annum. For the period from August 14, 2013, through September 30, 2013, the Partnership incurred $0.3 million of commitment fees.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
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Credit Risk
Our exposure to credit risk may be affected by our concentration of customers due to changes in economic or other conditions. Our customers include companies that may react differently to changing conditions. Our principal customers are QEP and QGC, who account for approximately 63% and 16%, respectively, of the Partnership's total revenues. We bear credit risk represented by our exposure to non-payment or non-performance by our customers, including QEP and QGC. Consequently, we are subject to the risk of non-payment or late payment by QEP and QGC of gathering fees, and this risk is greater than it would be with a broader customer base with a similar credit profile.
Our gathering agreement with QGC is the subject of ongoing litigation, in which QGC is disputing the calculation of the gathering rate and has been netting the disputed amount from its monthly payment of gathering fees to Field Services and the Partnership since the second quarter of 2012. As of September 30, 2013, the Partnership has deferred revenue of $7.0 million related to the QGC disputed amount. The Partnership has been indemnified by QEP for costs, expenses and other losses incurred by the Partnership in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement. For more information regarding the litigation with QGC, please see "Litigation" under "Note 6 - Commitments and Contingencies" to the unaudited consolidated financial statements included in Item 1 of Part I of this report.
We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on our principal customers, and in particular QEP, for our revenues. If QEP becomes unable to perform under the terms of our gathering agreements, or the Omnibus Agreement, it may significantly reduce our ability to make distributions to our unitholders.
Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses.
Critical Accounting Policies and Estimates
As of September 30, 2013, there have been no significant changes to our critical accounting policies and estimates as disclosed in our Prospectus.
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Supplemental Disclosures
As previously discussed, certain information contained in this report relates to periods that ended prior to the completion of the Offering, and prior to the effective dates of the agreements discussed herein. Consequently, the results discussed above include results for both the properties conveyed to the Partnership in connection with the Offering and properties retained by our Predecessor. We believe that historical data limited to only the properties conveyed to the Partnership in connection with the Offering is relevant and meaningful, enhances the discussion of the periods presented and is useful to the reader to better understand trends in our operations.
The following pro forma financial data is for informational purposes only and was derived from the Predecessor financial information removing the results of the assets retained by the Predecessor, consisting of the Uinta Basin Gathering System. Further, management does not believe that the financial data is necessarily comparable to the financial data reported by the Partnership for periods subsequent to the Offering, indicative of future results of the Partnership, or reflective of other transactions that resulted in the capitalization and start-up of the Partnership. See "Item 2 Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting the Comparability of Our Financial Results" within this report 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 Offering.
QEP Midstream Partners, LP Unaudited Pro Forma Financial Data | ||||||||||||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||
2013 | 2012 | change | % change | 2013 | 2012 | change | % change | |||||||||||||||||||||||
(in millions, except operating, per unit amounts and percentages) | ||||||||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||||||||
Gathering and transportation | $ | 31.5 | $ | 31.0 | $ | 0.5 | 2 | % | $ | 89.2 | $ | 89.3 | $ | (0.1 | ) | — | % | |||||||||||||
Condensate sales | 1.2 | 1.2 | — | — | % | 5.8 | 6.8 | (1.0 | ) | (15 | )% | |||||||||||||||||||
Total revenues | 32.7 | 32.2 | 0.5 | 2 | % | 95.0 | 96.1 | (1.1 | ) | (1 | )% | |||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||||||||
Gathering expenses | 5.8 | 5.2 | 0.6 | 12 | % | 17.4 | 15.3 | 2.1 | 14 | % | ||||||||||||||||||||
Operating Statistics | ||||||||||||||||||||||||||||||
Natural gas throughput in millions of MMBtu | ||||||||||||||||||||||||||||||
Gathering and transportation | 77.8 | 81.3 | (3.5 | ) | (4 | )% | 225.9 | 234.5 | (8.6 | ) | (4 | )% | ||||||||||||||||||
Equity interest(1) | 3.4 | 5.7 | (2.3 | ) | (40 | )% | 13.1 | 17.6 | (4.5 | ) | (26 | )% | ||||||||||||||||||
Total natural gas throughput | 81.2 | 87.0 | (5.8 | ) | (7 | )% | 239.0 | 252.1 | (13.1 | ) | (5 | )% | ||||||||||||||||||
Throughput attributable to noncontrolling interests(2) | (2.2 | ) | (3.1 | ) | 0.9 | (29 | )% | (7.5 | ) | (10.1 | ) | 2.6 | (26 | )% | ||||||||||||||||
Total throughput attributable to QEP Midstream or Predecessor | 79.0 | 83.9 | (4.9 | ) | (6 | )% | 231.5 | 242.0 | (10.5 | ) | (4 | )% | ||||||||||||||||||
Crude oil and condensate gathering system throughput volumes (in MBbls) | 1,253.7 | 1,399.7 | (146.0 | ) | (10 | )% | 3,913.3 | 4,131.0 | (217.7 | ) | (5 | )% | ||||||||||||||||||
Water gathering volumes (in MBbls) | 1,090.9 | 1,076.5 | 14.4 | 1 | % | 2,988.6 | 2,928.5 | 60.1 | 2 | % | ||||||||||||||||||||
Condensate sales volumes (in MBbls) | 14.8 | 15.7 | (0.9 | ) | (6 | )% | 71.0 | 77.6 | (6.6 | ) | (9 | )% | ||||||||||||||||||
Price | ||||||||||||||||||||||||||||||
Average gas gathering and transportation fee (per MMBtu) | $ | 0.34 | $ | 0.32 | $ | 0.02 | 6 | % | $ | 0.33 | $ | 0.32 | $ | 0.01 | 3 | % | ||||||||||||||
Average oil and condensate gathering fee (per barrel) | $ | 2.35 | $ | 2.14 | $ | 0.21 | 10 | % | $ | 2.42 | $ | 2.29 | $ | 0.13 | 6 | % | ||||||||||||||
Average water gathering fee (per barrel) | $ | 1.84 | $ | 1.83 | $ | 0.01 | 1 | % | $ | 1.82 | $ | 1.84 | $ | (0.02 | ) | (1 | )% | |||||||||||||
Average condensate sale price (per barrel) | $ | 80.05 | $ | 76.34 | $ | 3.71 | 5 | % | $ | 81.90 | $ | 86.94 | $ | (5.04 | ) | (6 | )% | |||||||||||||
(1) | Includes our 50% share of gross volumes from Three Rivers Gathering. |
(2) | Includes the 22% noncontrolling interest in Rendezvous Gas. |
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Three Months Ended September 30, 2013, compared to Three Months Ended September 30, 2012 - Pro Forma
Revenue
Gathering and transportation. Gathering and transportation revenues were $0.5 million, or 2%, higher on a pro forma basis in the third quarter of 2013 compared to the third quarter of 2012. This increase was attributable to natural gas gathering and transportation revenues which increased $0.5 million as a result of an increase in transportation revenue from Rendezvous Pipeline. Natural gas gathering revenue was flat period to period due to an increase of 6% in the average gathering rate offset by a decrease in volumes of 6%. The decrease in natural gas volumes was a result of a decrease in the Vermillion Gathering System throughput from declines in upstream drilling activity partially offset by an increase in natural gas gathering volumes in our Green River Gathering System due to an increase in QEP's Pinedale production.
Crude oil and condensate gathering revenue was flat in the third quarter of 2013 compared to the third quarter of 2012, on a pro forma basis, due to an 10% increase in the average rate offset by an 10% decrease in volumes due to lower throughput in the Green River Gathering System.
Condensate sales. Revenues from condensate sales were flat in the third quarter of 2013 compared to the third quarter of 2012, on a pro forma basis, due to a decrease in condensate sales volumes of 6% partially offset by an increase of 5% in average condensate sales price. The decrease in volumes is primarily attributable to a decrease in the Vermillion Gathering System throughput from declines in upstream drilling activity partially offset by an increase in our Green River Gathering System due to an increase in QEP's Pinedale production. The increase in the average condensate sales price is a result of the fixed priced condensate agreement that was entered into on August 14, 2013, with QEP that requires sales of our condensate at a fixed price of $82.25.
Operating Expenses
Gathering expenses. Gathering expenses increased $0.6 million, or 12%, in the third quarter of 2013 compared to the third quarter of 2012, on a pro forma basis, primarily due an increase in labor and benefits costs allocated to the contributed properties.
Nine Months Ended September 30, 2013, compared to Nine Months Ended September 30, 2012 - Pro Forma
Revenue
Gathering and transportation. Gathering and transportation revenues were $0.1 million lower on a pro forma basis for the nine months ended September 30, 2013, compared to the nine months ended September 30, 2012, due to a $0.2 million decrease in natural gas gathering revenue partially offset by a $0.1 million increase in water gathering revenue. The decrease in natural gas gathering revenue was due to a 4% decrease in volumes partially offset by a 3% increase in average gathering rate. The decrease in natural gas volumes was a result of a decrease in the Vermillion Gathering System throughput from declines in upstream drilling activity partially offset by an increase in natural gas gathering volumes in our Green River and North Dakota Gathering Systems due to an increase in QEP's production in these areas.
Water gathering revenue was higher on a pro forma basis for the nine months ended September 30, 2013, compared to the nine months ended September 30, 2012, due to increases in the Green River Gathering System. Crude oil and condensate gathering revenue was flat due to a 6% increase in the average rate offset by an 5% decrease in volumes due to lower throughput in the Green River Gathering System.
Condensate sales. Revenues from condensate sales decreased $1.0 million, or 15%, on a pro forma basis for the nine months ended September 30, 2013, compared to the nine months ended September 30, 2012, due to a decrease in condensate sales volumes of 9% and a 6% decrease in average condensate sales price. The decrease in volumes is primarily attributable to a decrease in the Vermillion Gathering System throughput from declines in upstream drilling activity and a decrease in our Green River Gathering System due to a new contract with QEP in mid-2012, which allows QEP to retain its proportionate share of condensate volumes.
Operating Expenses
Gathering expenses. Gathering expenses increased $2.1 million, or 14%, for the nine months ended September 30, 2013, compared to the nine months ended September 30, 2012, on a pro forma basis, primarily due an increase in labor and benefits costs allocated to the contributed properties.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
Prior to the Offering, our Predecessor's interest expense was an allocation of Field Service's interest expense on debt which consisted of two promissory notes between Field Services and QEP, each with a fixed rate of 6.0%, which were not subject to interest rate movements. The Partnership's new Credit Facility contains a variable interest rate that exposes us to volatility in interest rates. However, at September 30, 2013, we did not have any debt outstanding under the Credit Facility and therefore we did not have any debt subject to floating interest rates.
Commodity Price Risk
We bear a limited degree of commodity price risk with respect to our gathering contracts. Specifically, pursuant to our contracts, we retain and sell condensate that is recovered during the gathering of natural gas. Thus, a portion of our revenues is dependent upon the price received for the condensate. Condensate historically sells at a price representing a slight discount to the price of crude oil. We consider our exposure to commodity price risk associated with these arrangements to be minimal based on the amount of revenues generated under these arrangements compared to our overall revenues. Historically, we have not entered into commodity derivative instruments because of the minimal impact on our revenues, however, on August 14, 2013, the Partnership entered into a fixed price Condensate Purchase Agreement with QEP, which requires us to sell and QEP to purchase all of the condensate volumes collected on our gathering systems at a fixed price of $85.25 per barrel of product over a primary term of five years. In addition, we expect to utilize risk management tools to minimize future commodity price risk that could be associated with assets we may acquire or contracts we may enter into in the future.
Forward-Looking Statements
This quarterly report contains information that includes or is based upon "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements include statements relating to, among other things:
• | belief that the historical financial results of our Predecessor are not indicative of our future results; |
• | reasonableness of the methodologies for allocating general and administrative costs of our Predecessor; |
• | estimates of contingency losses and outcome of pending litigation and other legal proceedings; |
• | drilling activity on dedicated acreage and its impact on throughput levels and production; |
• | correlation of drilling activity with commodity prices and production levels; |
• | our ability to maximize operating profits by minimizing operating and maintenance costs; |
• | stability of operating and maintenance costs across broad ranges of throughput volumes; |
• | fluctuation of operating and maintenance costs from period to period; |
• | anticipated general and administrative expenses following the Offering; |
• | Adjusted EBITDA; |
• | trends impacting our business; |
• | anticipated levels of exploration and production activities in the areas we operate; |
• | impact of oil and natural gas prices on production rates; |
• | decline in production from the Pinedale Field; |
• | impact of inflation and our ability to recover higher operating costs from our customers; |
• | impact of interest rates on our stock price, cost of capital and ability to raise funds, expand operations or make future acquisitions; |
• | impact of regulations on our compliance costs, the time to obtain required permits and throughput in our gathering systems; |
• | acquisition of additional midstream assets from QEP and third parties; |
• | impact of changes to the funding of affiliated and third party transactions on the comparability of our cash flow statements, working capital analysis and liquidity discussion; |
• | changes in interest expense; |
• | future cash distributions; |
• | anticipated maintenance and expansion capital expenditures during fiscal 2013; |
• | variance of expansion capital expenditures from period to period; |
• | funding for acquisition and expansion capital expenditures; |
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• | maintenance of separate accounts and sources of liquidity and utilization of QEP's cash management system and expertise; |
• | sources of liquidity; |
• | sufficiency of cash generated from operations, borrowings under our revolving credit facility and issuance of additional debt and equity securities to satisfy short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions; |
• | exposure to credit risk resulting from the concentration of our customers; |
• | impact of QEP's failure to perform under the terms of our gathering agreements or the Omnibus Agreement; |
• | adequacy of our credit review procedures, loss reserves, customer deposits and collection procedures; |
• | usefulness of historical data related only to properties conveyed to us in connection with the Offering; |
• | supplemental disclosures regarding properties conveyed to us in the Offering; and |
• | utilization of risk management tools to minimize future commodity price risks. |
Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
• | changes in general economic conditions; |
• | competitive conditions in our industry; |
• | actions taken by third-party operators, processors and transporters; |
• | the demand for oil and natural gas storage and transportation services; |
• | our ability to successfully implement our business plan; |
• | our ability to complete internal growth projects on time and on budget; |
• | the price and availability of debt and equity financing; |
• | the availability and price of oil and natural gas to the consumer compared to the price of alternative and competing fuels; |
• | competition from the same and alternative energy sources; |
• | energy efficiency and technology trends; |
• | operating risks and hazards incidental to transporting, storing and processing oil and natural gas, as applicable; |
• | natural disasters, weather-related delays, casualty losses and other matters beyond our control; |
• | production trends in our areas of operations; |
• | interest rates; |
• | labor relations; |
• | large customer defaults; |
• | change in availability and cost of capital; |
• | changes in tax status; |
• | the effect of existing and future laws and government regulations; |
• | the effects of future litigation; and |
• | certain factors discussed elsewhere in this report and our Prospectus. |
Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities law.
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ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of September 30, 2013. Based on such evaluation, our management has concluded that, as of September 30, 2013, our disclosure controls and procedures are designed and effective to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information is accumulated and communicated to our management, including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.
In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions.
Changes in Internal Controls
There were no changes in our internal controls over financial reporting during the quarter ended September 30, 2013, that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.
Internal Control Over Financial Reporting
The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules that generally require every company that files reports with the SEC to include a management report on such company's internal control over financial reporting in its annual report. In addition, our independent registered public accounting firm must attest to our internal control over financial reporting. Our first Annual Report on Form 10-K will not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to new public companies. Management will be required to provide an assessment of effectiveness of our internal control over financial reporting in our Annual Report on Form 10-K for the year ended December 31, 2014. We are not required to comply with the auditor attestation requirement of Section 404 of the Sarbanes-Oxley Act while we qualify as an "emerging growth company" as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act.
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PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Information regarding legal proceedings is set forth under "Litigation" in "Note 9 - Commitments and Contingencies" to the Predecessor's unaudited consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q and is incorporated herein by reference.
ITEM 1A. RISK FACTORS
We are subject to various risks and uncertainties in the course of our business. Risk factors relating to the Company are set forth under "Risk Factors" in our Prospectus. No material changes to such risk factors have occurred during the three months ended September 30, 2013.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
On August 8, 2013, our Registration Statement on Form S-1 (SEC Registration No 333-188487), as amended (the "Registration Statement"), which we filed with the SEC relating to the Offering, became effective. The Registration Statement registered 23,000,000 common units (including 3,000,000 over-allotment common units) with a maximum aggregate offering price of $483.0 million. Wells Fargo Securities, LLC, Morgan Stanley & Co. LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., and J.P. Morgan Securities LLC, served as the joint book running managers for the Offering. Upon the closing of the Offering on August 14, 2013, we sold 20,000,000 common units representing limited partner interests in the Partnership at a price to the public of $21.00 per common unit. Net proceeds from the sale of the 20,000,000 common units were approximately $390.7 million, after deducting underwriting discounts and commissions of approximately $25.2 million and offering expenses of approximately $4.1 million (including a $2.1 million structuring fee paid to Wells Fargo Securities, LLC). We used the net proceeds to (i) make a cash distribution to QEP of $292.2 million, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to us, (ii) repay our outstanding long-term debt balance of $95.5 million, and (iii) pay revolving credit facility origination fees of $3.0 million.
At the closing of the Offering, we also issued (a) 1,090,000 unregistered general partner units and all our incentive distribution rights to the General Partner in exchange for its interest in the Operating Company, and (b) 6,701,750 unregistered common units and 26,705,000 unregistered subordinated units to Field Services as partial consideration for its interests in the Operating Company and a right to receive a distribution from the Partnership. These transactions were exempt from registration under Section 4(2) of the Securities Act, as they did not involve a public offering.
On each of August 21, 2013, and September 4, 2013, we issued an additional 1,500,000 common units to the public following partial exercises by the underwriters of their over-allotment option to purchase additional common units. The net proceeds from the full exercise of the underwriters' option of $58.9 million, net of underwriters' discounts and structuring fees of $4.1 million, were used to redeem additional common units from Field Services.
The gross aggregate offering amount of the common units sold pursuant to the Registration Statement was $483.0 million. From the effective date of the Registration Statement through September 30, 2013, we incurred underwriting discounts and commissions of $29.0 million and structuring fees and offering expenses of approximately $4.4 million.
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ISSUER PURCHASES OF EQUITY SECURITIES
The following table sets forth information with respect to repurchases by the Partnership of its common units during the period indicated.
Period | Total Number of Units Purchased(1) | Average Price Paid per Unit | Total Number of Units Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Dollar Value) of Units that May Yet Be Purchased Under the Plans or Programs | |||||||
August 1, 2013, through August 31, 2013 | 1,500,000 | $ | 21.00 | — | — | ||||||
September 1, 2013, through September 30, 2013 | 1,500,000 | $ | 21.00 | — | — | ||||||
(1) The Partnership redeemed 3,000,000 common units from Field Services with the net proceeds from the sale of 3,000,000 common units pursuant to the exercise of the underwriters' over-allotment option.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
None.
ITEM 5. OTHER INFORMATION
Indemnification Agreements
On November 4, 2013, the General Partner entered into an indemnification agreement with its independent directors (the “Indemnification Agreement”). The Indemnification Agreement supplements the indemnification rights provided under the Partnership’s agreement of limited partnership. The Indemnification Agreement requires the Partnership to indemnify the directors to the fullest extent permitted under Delaware law against liability that may arise by reason of her service to the Partnership and to advance expenses incurred as a result of any proceeding against her as to which she could be indemnified. The Indemnification Agreement also provides procedures for the determination of the indemnitees' right to receive indemnification and the advancement of expenses. The Partnership anticipates that it will enter into substantially similar Indemnification Agreements with any new director.
The foregoing is a summary of the material terms of the Indemnification Agreement. A copy of the form of Indemnification Agreement is filed as Exhibit 10.10 to this Quarterly Report on Form 10-Q and is incorporated herein by reference.
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ITEM 6. EXHIBITS
The following exhibits are being filed as part of this report:
Exhibit No. | Exhibits | |
3.1 | First Amended and Restated Agreement of Limited Partnership of QEP Midstream Partners, LP, dated August 16, 2013, by and between QEP Midstream Partners GP, LLC and QEP Field Services Company, incorporated by reference to Exhibit 3.1 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013. | |
10.1 | QEP Midstream Partners, LP 2013 Long-Term Incentive Plan, incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 13, 2013. | |
10.2 | Form of QEP Midstream Partners, LP 2013 Long-Term Incentive Plan Phantom Unit Agreement, incorporated by reference to Exhibit 10.4 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013. | |
10.3 | Form of QEP Midstream Partners, LP 2013 Long-Term Incentive Plan Common Unit Agreement, incorporated by reference to Exhibit 10.13 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 29, 2013. | |
10.4 | Contribution, Conveyance and Assumption Agreement, dated as of August 14, 2013, by and among QEP Midstream Partners, LP, QEP Midstream Partners GP, LLC, QEP Field Services Company and QEP Midstream Partners Operating, LLC, incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013. | |
10.5 | Omnibus Agreement, dated as of August 14, 2013, by and among QEP Midstream Partners, LP, QEP Midstream Partners GP, LLC, QEP Resources, Inc., QEP Field Services Company and QEP Midstream Partners Operating, LLC, incorporated by reference to Exhibit 10.2 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013. | |
10.6 | Credit Agreement, dated as of August 14, 2013, among QEP Midstream Partners Operating, LLC, as the borrower, QEP Midstream Partners, LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders from time to time party thereto, incorporated by reference to Exhibit 10.3 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013. | |
10.7 | Gas Gathering Agreement, dated September 1, 1993, between Questar Gas Company (f/k/a Mountain Fuel Supply Company) and QEP Field Services Company (f/k/a Questar Pipeline Company), incorporated by reference to Exhibit 10.6 to the Company's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 26, 2013, as amended by Amendment to the Gas Gathering Agreement, dated February 6, 1998, between Questar Gas Company and QEP Field Services Company (f/k/a Questar Gas Management Company), incorporated by reference to Exhibit 10.7 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 26, 2013. | |
10.8 | Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company), incorporated by reference to Exhibit 10.8 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013, as amended by (i) First Amendment, dated March 1, 2006, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company and QEP Field Services Company, incorporated by reference to Exhibit 10.9 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013; (ii) Second Amendment, dated August 16, 2007, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company and QEP Field Services Company, incorporated by reference to Exhibit 10.10 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013; (iii) Third Amendment, dated March 2, 2010, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company and QEP Field Services Company, incorporated by reference to Exhibit 10.11 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013; and (iv) Fourth Amendment, dated July 1, 2011, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company and QEP Field Services Company, incorporated by reference to Exhibit 10.12 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013. Certain portions of the Amended and Restated Gas Gathering Agreement, the First Amendment, the Third Amendment and the Fourth Amendment have been omitted pursuant to a confidential treatment request granted by the Securities and Exchange Commission. | |
10.9 | Form of QEP Midstream Partners, GP, LLC Indemnification Agreement for directors. | |
31.1 | Certification signed by C. B. Stanley, QEP Midstream Partners, LP's Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
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31.2 | Certification signed by Richard J. Doleshek, QEP Midstream Partners, LP's Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1 | Certification signed by C. B. Stanley and Richard J. Doleshek, QEP Midstream Partners, LP's Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
101.INS | XBRL Instance Document | |
101.SCH | XBRL Schema Document | |
101.CAL | XBRL Calculation Linkbase Document | |
101.LAB | XBRL Label Linkbase Document | |
101.PRE | XBRL Presentation Linkbase Document | |
101.DEF | XBRL Definition Linkbase Document | |
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SIGNATURES
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.
QEP MIDSTREAM PARTNERS, LP | ||
(Registrant) | ||
By: | QEP Midstream Partners GP, LLC | |
(as General Partner) | ||
November 8, 2013 | /s/ Charles B. Stanley | |
Charles B. Stanley, | ||
Chairman, President and Chief Executive Officer | ||
November 8, 2013 | /s/ Richard J. Doleshek | |
Richard J. Doleshek, | ||
Executive Vice President, | ||
Chief Financial Officer and Treasurer | ||
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