Attached files
| file | filename |
|---|---|
| EX-32.2 - EXHIBIT 32.2 - CVR Refining, LP | cvrrq22017exhibit322.htm |
| EX-32.1 - EXHIBIT 32.1 - CVR Refining, LP | cvrrq22017exhibit321.htm |
| EX-31.2 - EXHIBIT 31.2 - CVR Refining, LP | cvrrq22017exhibit312.htm |
| EX-31.1 - EXHIBIT 31.1 - CVR Refining, LP | cvrrq22017exhibit311.htm |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One) | |
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2017 | |
OR | |
¨ | 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: 001-35781
CVR Refining, LP
(Exact name of registrant as specified in its charter)
Delaware | 37-1702463 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
2277 Plaza Drive, Suite 500 | |
Sugar Land, Texas (Address of principal executive offices) | 77479 (Zip Code) |
(281) 207-3200
(Registrant's telephone number, including area code)
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 þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o |
(Do not check if a smaller reporting company) | ||
Smaller reporting company o | Emerging growth company o | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes o No þ
There were 147,600,000 common units outstanding at July 25, 2017.
CVR REFINING, LP AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
For The Quarter Ended June 30, 2017
Page No. | ||
2
GLOSSARY OF SELECTED TERMS
The following are definitions of certain terms used in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2017 (this "Report").
2016 Form 10-K — Our Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on February 21, 2017.
2022 Notes — $500.0 million aggregate principal amount of 6.5% Senior Notes due 2022, which were issued by Refining LLC and Coffeyville Finance on October 23, 2012 and fully and unconditionally guaranteed by the Partnership and each of Refining LLC's domestic subsidiaries other than Coffeyville Finance.
2-1-1 crack spread — The approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate. The 2-1-1 crack spread is expressed in dollars per barrel.
Amended and Restated ABL Credit Facility — Our senior secured asset based revolving credit facility with a group of lenders and Wells Fargo Bank, National Association as administrative agent and collateral agent.
barrel — Common unit of measure in the oil industry which equates to 42 gallons.
blendstocks — Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel fuel; these may include natural gasoline, fluid catalytic cracking unit or FCCU gasoline, ethanol, reformate or butane, among others.
bpd — Abbreviation for barrels per day.
bpcd — Abbreviation for barrels per calendar day, which refers to the total number of barrels processed in a refinery within a year, divided by the total number of days in the year (365 or 366 days), thus reflecting all operational and logistical limitations.
bulk sales — Volume sales through third-party pipelines, in contrast to tanker truck quantity rack sales.
capacity — Capacity is defined as the throughput a process unit is capable of sustaining, either on a barrel per calendar or stream day basis. The throughput may be expressed in terms of maximum sustainable, nameplate or economic capacity. The maximum sustainable or nameplate capacities may not be the most economical. The economic capacity is the throughput that generally provides the greatest economic benefit based on considerations such as crude oil and other feedstock costs, product values and downstream unit constraints.
catalyst — A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.
Coffeyville Finance — Coffeyville Finance Inc., a wholly owned subsidiary of Refining LLC and an indirect wholly-owned subsidiary of the Partnership.
crack spread — A simplified calculation that measures the difference between the price for light products and crude oil. For example, the 2-1-1 crack spread is often referenced and represents the approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate.
CRLLC — Coffeyville Resources, LLC, a wholly-owned subsidiary of CVR Energy.
CRPLLC — Coffeyville Resources Pipeline, LLC.
CRRM — Coffeyville Resource Refining & Marketing, LLC, a wholly-owned subsidiary of Refining LLC and indirect wholly-owned subsidiary of the Partnership.
CVR Energy — CVR Energy, Inc., a publicly traded company listed on the NYSE under the ticker symbol "CVI," which indirectly owns our general partner and a majority of our common units.
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CVR Partners — CVR Partners, LP, a publicly traded limited partnership listed on the NYSE under the ticker symbol "UAN," which produces and markets nitrogen fertilizers in the form of urea ammonium nitrate ("UAN") and ammonia.
CVR Refining — CVR Refining, LP and its subsidiaries.
CVR Refining GP or general partner — CVR Refining GP, LLC, an indirect wholly-owned subsidiary of CVR Energy.
distillates — Primarily diesel fuel, kerosene and jet fuel.
ethanol — A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate.
feedstocks — Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products, such as gasoline, diesel fuel and jet fuel, during the refining process.
Group 3 — A geographic subset of the PADD II region comprising refineries in Oklahoma, Kansas, Missouri, Nebraska and Iowa. Current Group 3 refineries include our Coffeyville and Wynnewood refineries; the Valero Ardmore refinery in Ardmore, OK; HollyFrontier's Tulsa refinery in Tulsa, OK and El Dorado refinery in El Dorado, KS; Phillips 66's Ponca City refinery in Ponca City, OK; and CHS Inc.'s refinery in McPherson, KS.
heavy crude oil — A relatively inexpensive crude oil characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel fuel.
independent petroleum refiner — A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil throughputs in its refinery operations from third parties.
intercompany credit facility — A $250.0 million senior unsecured revolving credit facility between CRLLC and us.
light crude oil — A relatively expensive crude oil characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel fuel.
natural gas liquids — Natural gas liquids, often referred to as NGLs, are feedstocks used in the manufacture of refined fuels, as well as products of the refining process. Common NGLs used include propane, isobutane, normal butane and natural gasoline.
PADD II — Midwest Petroleum Area for Defense District which includes Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee and Wisconsin.
Partnership — CVR Refining and its subsidiaries.
petroleum coke (pet coke) — A coal-like substance that is produced during the refining process.
rack sales — Sales which are made at terminals into third-party tanker trucks.
refined products — Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.
Refining LLC — CVR Refining, LLC, a wholly-owned subsidiary of the Partnership.
RFS — Renewable Fuel Standard of the United States Environmental Protection Agency.
RINs — Renewable fuel credits, known as renewable identification numbers.
sour crude oil — A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.
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sweet crude oil — A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.
throughput — The volume processed through a unit or a refinery or transported on a pipeline.
turnaround — A periodically required standard procedure to inspect, refurbish, repair and maintain our refineries. This process involves the shutdown and inspection of major processing units and occurs every four to five years.
Velocity — Velocity Central Oklahoma Pipeline LLC.
Vitol — Vitol Inc.
Vitol Agreement — The Amended and Restated Crude Oil Supply Agreement between Vitol and CCRM.
VPP — Velocity Pipeline Partners, LLC.
WCS — Western Canadian Select crude oil, a medium to heavy, sour crude oil, characterized by an American Petroleum Institute gravity ("API gravity") of between 20 and 22 degrees and a sulfur content of approximately 3.3 weight percent.
WTI — West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity between 39 and 41 degrees and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.
WTS — West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of between 30 and 32 degrees and a sulfur content of approximately 2.0 weight percent.
yield — The percentage of refined products that is produced from crude oil and other feedstocks.
5
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CVR REFINING, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30, 2017 | December 31, 2016 | ||||||
(unaudited) | |||||||
(in millions, except unit data) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 515.7 | $ | 314.1 | |||
Accounts receivable, net of allowance for doubtful accounts of $1.3 and $0.5, including $0.3 and $0.1 due from affiliates at June 30, 2017 and December 31, 2016, respectively | 127.8 | 138.1 | |||||
Inventories | 256.3 | 291.1 | |||||
Prepaid expenses and other current assets, including $1.3 and $1.2 due from affiliates at June 30, 2017 and December 31, 2016, respectively | 38.8 | 60.3 | |||||
Total current assets | 938.6 | 803.6 | |||||
Property, plant, and equipment, net of accumulated depreciation | 1,495.2 | 1,515.0 | |||||
Other long-term assets | 13.3 | 13.3 | |||||
Total assets | $ | 2,447.1 | $ | 2,331.9 | |||
LIABILITIES AND PARTNERS' CAPITAL | |||||||
Current liabilities: | |||||||
Note payable and capital lease obligations | $ | 2.0 | $ | 1.8 | |||
Accounts payable, including $4.4 and $4.6 due to affiliates at June 30, 2017 and December 31, 2016, respectively | 214.5 | 225.9 | |||||
Personnel accruals, including $3.0 and $3.0 due to affiliates at June 30, 2017 and December 31, 2016, respectively | 18.3 | 19.3 | |||||
Accrued taxes other than income taxes | 26.7 | 25.2 | |||||
Accrued expenses and other current liabilities, including $6.9 and $8.9 due to affiliates at June 30, 2017 and December 31, 2016, respectively | 296.7 | 217.7 | |||||
Total current liabilities | 558.2 | 489.9 | |||||
Long-term liabilities: | |||||||
Long-term debt and capital lease obligations, net of current portion | 539.1 | 539.7 | |||||
Other long-term liabilities, including $0.5 and $0.6 due to affiliates at June 30, 2017 and December 31, 2016, respectively | 5.3 | 5.6 | |||||
Total long-term liabilities | 544.4 | 545.3 | |||||
Commitments and contingencies | |||||||
Partners’ capital: | |||||||
Common unitholders, 147,600,000 units issued and outstanding at June 30, 2017 and December 31, 2016 | 1,344.5 | 1,296.7 | |||||
General partner interest | — | — | |||||
Total partners’ capital | 1,344.5 | 1,296.7 | |||||
Total liabilities and partners’ capital | $ | 2,447.1 | $ | 2,331.9 | |||
See accompanying notes to the condensed consolidated financial statements.
6
CVR REFINING, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(unaudited) | |||||||||||||||
(in millions, except per unit data) | |||||||||||||||
Net sales | $ | 1,338.2 | $ | 1,164.4 | $ | 2,761.7 | $ | 1,998.4 | |||||||
Operating costs and expenses: | |||||||||||||||
Cost of materials and other | 1,208.0 | 941.9 | 2,409.3 | 1,664.2 | |||||||||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 86.3 | 84.0 | 188.4 | 201.7 | |||||||||||
Depreciation and amortization | 31.7 | 30.9 | 65.0 | 61.8 | |||||||||||
Cost of sales | 1,326.0 | 1,056.8 | 2,662.7 | 1,927.7 | |||||||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization as reflected below) | 18.9 | 16.8 | 38.9 | 35.3 | |||||||||||
Depreciation and amortization | 0.7 | 0.7 | 1.5 | 1.3 | |||||||||||
Total operating costs and expenses | 1,345.6 | 1,074.3 | 2,703.1 | 1,964.3 | |||||||||||
Operating income (loss) | (7.4 | ) | 90.1 | 58.6 | 34.1 | ||||||||||
Other income (expense): | |||||||||||||||
Interest expense and other financing costs | (12.0 | ) | (10.1 | ) | (23.2 | ) | (20.9 | ) | |||||||
Interest income | 0.2 | — | 0.2 | — | |||||||||||
Gain (loss) on derivatives, net | — | (1.9 | ) | 12.2 | (3.1 | ) | |||||||||
Other income (expense), net | — | — | — | — | |||||||||||
Total other expense | (11.8 | ) | (12.0 | ) | (10.8 | ) | (24.0 | ) | |||||||
Income (loss) before income tax expense | (19.2 | ) | 78.1 | 47.8 | 10.1 | ||||||||||
Income tax expense (benefit) | — | — | — | — | |||||||||||
Net income (loss) | $ | (19.2 | ) | $ | 78.1 | $ | 47.8 | $ | 10.1 | ||||||
Net income (loss) per common unit - basic and diluted | $ | (0.13 | ) | $ | 0.53 | $ | 0.32 | $ | 0.07 | ||||||
Weighted-average common units outstanding: | |||||||||||||||
Basic and diluted | 147.6 | 147.6 | 147.6 | 147.6 | |||||||||||
See accompanying notes to the condensed consolidated financial statements.
7
CVR REFINING, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
Common Units Issued | Common Unitholders | General Partner Interest | Total Partners' Capital | |||||||||||
(unaudited) | ||||||||||||||
(in millions, except unit data) | ||||||||||||||
Balance at December 31, 2016 | 147,600,000 | $ | 1,296.7 | $ | — | $ | 1,296.7 | |||||||
Net income | — | 47.8 | — | 47.8 | ||||||||||
Balance at June 30, 2017 | 147,600,000 | $ | 1,344.5 | $ | — | $ | 1,344.5 | |||||||
See accompanying notes to the condensed consolidated financial statements.
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CVR REFINING, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Ended June 30, | |||||||
2017 | 2016 | ||||||
(unaudited) | |||||||
(in millions) | |||||||
Cash flows from operating activities: | |||||||
Net income | $ | 47.8 | $ | 10.1 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation and amortization | 66.5 | 63.1 | |||||
Allowance for doubtful accounts | 0.8 | 0.2 | |||||
Amortization of deferred financing costs | 0.9 | 0.9 | |||||
Loss on disposition of assets | 0.4 | 0.3 | |||||
Share-based compensation | 4.6 | 0.6 | |||||
Loss (gain) on derivatives, net | (12.2 | ) | 3.1 | ||||
Current period settlements on derivative contracts | 1.1 | 28.5 | |||||
Income from equity method investment | (0.1 | ) | — | ||||
Changes in assets and liabilities: | |||||||
Accounts receivable | 9.5 | (45.3 | ) | ||||
Inventories | 34.8 | (19.3 | ) | ||||
Prepaid expenses and other current assets | 21.1 | (5.9 | ) | ||||
Other long-term assets | 0.1 | 0.2 | |||||
Accounts payable | (9.9 | ) | (28.6 | ) | |||
Accrued expenses and other current liabilities | 86.2 | 30.4 | |||||
Other long-term liabilities | (0.3 | ) | 2.5 | ||||
Net cash provided by operating activities | 251.3 | 40.8 | |||||
Cash flows from investing activities: | |||||||
Capital expenditures | (47.4 | ) | (68.0 | ) | |||
Investment in affiliate | (1.4 | ) | — | ||||
Net cash used in investing activities | (48.8 | ) | (68.0 | ) | |||
Cash flows from financing activities: | |||||||
Payment of capital lease obligations | (0.9 | ) | (0.8 | ) | |||
Net cash used in financing activities | (0.9 | ) | (0.8 | ) | |||
Net increase (decrease) in cash and cash equivalents | 201.6 | (28.0 | ) | ||||
Cash and cash equivalents, beginning of period | 314.1 | 187.3 | |||||
Cash and cash equivalents, end of period | $ | 515.7 | $ | 159.3 | |||
Supplemental disclosures: | |||||||
Cash paid for interest net of capitalized interest of $0.4 and $3.4 in 2017 and 2016, respectively | $ | 22.3 | $ | 20.1 | |||
Non-cash investing and financing activities: | |||||||
Construction in process additions included in accounts payable | $ | 7.7 | $ | 9.5 | |||
Change in accounts payable related to construction in process additions | $ | (1.6 | ) | $ | (11.0 | ) | |
See accompanying notes to the condensed consolidated financial statements.
9
CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2017
(unaudited)
(1) Organization and Nature of Business
CVR Refining, LP and subsidiaries ("CVR Refining" or the "Partnership") is an independent petroleum refiner and marketer of high value transportation fuels. CVR Refining is a Delaware limited partnership, formed in September 2012 by Coffeyville Resources, LLC ("CRLLC"), a wholly-owned subsidiary of CVR Energy, Inc. ("CVR Energy"). CVR Refining completed the initial public offering of its common units representing limited partner interests (the "Initial Public Offering") on January 23, 2013. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR."
The Partnership owns a complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and a complex crude oil refinery in Wynnewood, Oklahoma. As of June 30, 2017, CRLLC owned 100% of the Partnership's noneconomic general partner interest and approximately 66% of the Partnership's outstanding limited partner interests. As of June 30, 2017, Icahn Enterprises L.P. ("IEP") and its affiliates owned approximately 82% of CVR Energy's outstanding shares.
Management and Operations
The Partnership is party to a services agreement pursuant to which the Partnership and its general partner obtain certain management and other services from CVR Energy. The Partnership's general partner manages the Partnership's activities subject to the terms and conditions specified in the Partnership's partnership agreement. The operations of the general partner, in its capacity as general partner, are managed by its board of directors. Actions by the general partner that are made in its individual capacity are made by CVR Refining Holdings, LLC, a subsidiary of CRLLC, as the sole member of the Partnership's general partner and not by the board of directors of the general partner. The members of the board of directors of the Partnership's general partner are not elected by the Partnership's unitholders and are not subject to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business.
The Partnership has adopted a policy pursuant to which it will distribute all of the available cash it generates each quarter. The available cash for distribution for each quarter will be determined by the board of directors of the Partnership's general partner following the end of such quarter and will generally be distributed within 60 days of quarter end. The partnership agreement does not require that the Partnership make cash distributions on a quarterly basis or at all, and the board of directors of the general partner of the Partnership can change the distribution policy at any time.
(2) Basis of Presentation
The accompanying condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles ("GAAP") and in accordance with the rules and regulations of the Securities and Exchange Commission (the "SEC"). These condensed consolidated financial statements should be read in conjunction with the December 31, 2016 audited consolidated financial statements and notes thereto included in CVR Refining's Annual Report on Form 10-K for the year ended December 31, 2016, which was filed with the SEC on February 21, 2017 (the "2016 Form 10-K").
The condensed consolidated financial statements include certain selling, general and administrative expenses (exclusive of depreciation and amortization) and direct operating expenses (exclusive of depreciation and amortization) that CVR Energy and its affiliates incurred on behalf of and charged to the Partnership. These related party transactions are governed by the services agreement. See Note 14 ("Related Party Transactions") for additional discussion of the services agreement and billing of certain costs.
In the opinion of the Partnership's management, the accompanying condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments) that are necessary to fairly present the financial position of the Partnership as of June 30, 2017 and December 31, 2016, the results of operations of the Partnership for the three and six month periods ended June 30, 2017 and 2016, the changes in partners' capital for the Partnership for the six month period ended June 30, 2017 and the cash flows of the Partnership for the six month periods ended June 30, 2017 and 2016.
10
CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
The preparation of the condensed consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates. Results of operations and cash flows for the interim periods presented are not necessarily indicative of the results that will be realized for the year ending December 31, 2017 or any other interim or annual period.
(3) Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, creating a new topic, FASB Accounting Standards Codification ("ASC") Topic 606, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes revenue recognition requirements in FASB ASC Topic 605, “Revenue Recognition.” This ASU requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. In addition, an entity is required to disclose sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard is effective for interim and annual periods beginning after December 15, 2017. The Partnership has developed an implementation plan to adopt the new standard. As part of this plan, the Partnership is currently assessing the impact of the new guidance on its business processes, business and accounting systems, and consolidated financial statements and related disclosures, which involves review of existing revenue streams, evaluation of accounting policies and identification of the types of arrangements where differences may arise in the conversion to the new standard. The Partnership expects to complete the assessment phase of its implementation plan during the third quarter after which the Partnership will initiate the design and implementation phases of the plan, including implementing any changes to existing business processes and systems to accommodate the new standard, during 2017. The Partnership will adopt this standard as of January 1, 2018 using the modified retrospective application method. To date, the Partnership has not identified any material differences in its existing revenue recognition methods that would require modification under the new standard.
In February 2016, the FASB issued ASU 2016-02, “Leases” (“ASU 2016-02”), creating a new topic, FASB ASC Topic 842, "Leases," which supersedes lease requirements in FASB ASC Topic 840, "Leases." The new standard revises accounting for operating leases by a lessee, among other changes, and requires a lessee to recognize a liability to make lease payments and an asset representing its right to use the underlying asset for the lease term in the balance sheet. The standard is effective for the first interim and annual periods beginning after December 15, 2018, with early adoption permitted. At adoption, ASU 2016-02 will be applied using a modified retrospective application method. The Partnership is formulating an assessment and implementation plan to adopt the new standard. The Partnership expects its assessment and implementation plan to be ongoing during 2017 and 2018 and is currently unable to reasonably estimate the impact of adopting the new leases standard on its consolidated financial statements and footnote disclosures.
(4) Share-Based Compensation
Certain employees of CVR Refining and employees of CVR Energy and its subsidiaries who perform services for CVR Refining participate in the equity compensation plans of CVR Refining's affiliates. Accordingly, CVR Refining has recorded compensation expense for these plans in accordance with Staff Accounting Bulletin ("SAB") Topic 1-B, "Allocations of Expenses and Related Disclosures in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity," and in accordance with guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. All compensation expense related to these plans for full-time employees of CVR Refining has been attributed 100% to CVR Refining. For employees of CVR Energy performing services for CVR Refining, CVR Refining recorded share-based compensation relative to the percentage of time spent by each employee providing services to CVR Refining as compared to the total calculated share-based compensation by CVR Energy.
Long-Term Incentive Plan—CVR Energy
CVR Energy has a Long-Term Incentive Plan ("CVR Energy LTIP") that permits the grant of options, stock appreciation rights, restricted shares, restricted share units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance based restricted stock). As of June 30, 2017, only grants of performance units remain outstanding under the CVR Energy LTIP. Individuals who are eligible to receive awards and grants under the CVR Energy LTIP include CVR Energy's or its subsidiaries' (including CVR Refining) employees, officers, consultants and directors.
11
CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
Performance Unit Awards
In December 2016, CVR Energy entered into a performance unit award agreement (the "2016 Performance Unit Award Agreement") with its Chief Executive Officer. Compensation cost for the 2016 Performance Unit Award Agreement will be recognized over the performance cycle from January 1, 2017 to December 31, 2017. The performance unit award of 3,500 performance units under the 2016 Performance Unit Award Agreement represents the right to receive, upon vesting, a cash payment equal to $1,000 multiplied by the applicable performance factor. The amount paid pursuant to the award, if any, will be paid following the end of the performance cycle for the award, but no later than March 6, 2018. The Partnership will be responsible for reimbursing CVR Energy for its portion of the performance unit awards. Assuming a target performance threshold and that the allocation of costs from CVR Energy remains consistent with the allocation percentages in place at June 30, 2017, there was approximately $0.9 million of total unrecognized compensation cost related to the 2016 Performance Unit Award Agreement to be recognized over a weighted-average period of approximately 0.5 years. In December 2015, CVR Energy entered into a performance unit award agreement with its Chief Executive Officer with terms substantially the same as the 2016 Performance Unit Award Agreement and with a performance cycle from January 1, 2016 to December 31, 2016. Total compensation expense recorded for each of the three and six months ended June 30, 2017 and 2016 related to the performance unit awards was approximately $0.4 million and $0.9 million, respectively. As of June 30, 2017 and December 31, 2016, the Partnership had a liability of $0.9 million and $1.7 million, respectively, for its portion of the performance unit awards, which is recorded in accrued expenses and other current liabilities on the Condensed Consolidated Balance Sheets.
Incentive Unit Awards
CVR Energy has granted awards of incentive units and distribution equivalent rights to certain employees of CRLLC, CVR Energy and CVR GP, LLC. The awards are generally graded vesting awards, which are expected to vest over three years with one-third of each award vesting each year. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. Each incentive unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average fair market value of one unit of the Partnership's common units in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the Partnership from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest.
Assuming the portion of time spent on CVR Refining related matters by CVR Energy employees providing services to CVR Refining remains consistent with the amount of services provided during the six months ended June 30, 2017, there was approximately $3.4 million of total unrecognized compensation cost related to the incentive unit awards to be recognized over a weighted-average period of approximately 1.3 years. Inclusion of the vesting table is not considered meaningful due to changes in allocation percentages that may occur from time to time. The unrecognized compensation expense has been determined by the number of incentive units and associated distribution equivalent rights and respective allocation percentages for individuals for whom, as of June 30, 2017, compensation expense has been allocated to the Partnership. Total compensation expense recorded for the three months ended June 30, 2017 and 2016 related to the awards was approximately $0.8 million and $0.1 million, respectively. Total compensation expense recorded for the six months ended June 30, 2017 and 2016 related to the awards was approximately $1.6 million and nominal, respectively. The Partnership is responsible for reimbursing CVR Energy for its allocated portion of the incentive unit awards.
As of June 30, 2017 and December 31, 2016, the Partnership had a liability of approximately $3.0 million and $1.5 million, respectively, for its allocated portion of non-vested incentive units and associated distribution equivalent rights, which is recorded in accrued expenses and other current liabilities on the Condensed Consolidated Balance Sheets.
Long-Term Incentive Plan – CVR Refining
CVR Refining has a long-term incentive plan ("CVR Refining LTIP") that provides for the grant of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards, other-unit based awards, cash awards, performance awards, and distribution equivalent rights, each in respect of common units. The maximum number of common units issuable under the CVR Refining LTIP is 11,070,000. Individuals who are eligible to receive awards under the CVR Refining LTIP include (i) employees of the Partnership and its subsidiaries, (ii) employees of the general partner, (iii) members of the board of directors of
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
the general partner and (iv) certain employees, consultants and directors of CRLLC and CVR Energy who perform services for the benefit of the Partnership.
Awards of phantom units and distribution equivalent rights have been granted to employees of the Partnership and its subsidiaries, its general partner and certain employees of CRLLC and CVR Energy who perform services solely for the benefit of the Partnership. The awards are generally graded vesting awards, which are expected to vest over three years with one-third of each award vesting each year. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. Each phantom unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average fair market value of one unit of the Partnership's common units in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the Partnership from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest.
A summary of phantom unit activity and changes under the CVR Refining LTIP during the six months ended June 30, 2017 is presented below:
Phantom Units | Weighted- Average Grant-Date Fair Value | |||||
Non-vested at January 1, 2017 | 904,855 | $ | 12.38 | |||
Granted | 36,257 | 9.57 | ||||
Vested | (2,038 | ) | 11.36 | |||
Forfeited | (47,175 | ) | 16.88 | |||
Non-vested at June 30, 2017 | 891,899 | $ | 12.03 | |||
As of June 30, 2017, there was approximately $5.1 million of total unrecognized compensation cost related to the awards under the CVR Refining LTIP to be recognized over a weighted-average period of 1.3 years. Total compensation expense (credit) recorded for the three months ended June 30, 2017 and 2016 related to the awards under the CVR Refining LTIP was approximately $1.2 million and $(0.3) million, respectively. Total compensation expense recorded for the six months ended June 30, 2017 and 2016 related to the awards under the CVR Refining LTIP was approximately $2.2 million and nominal, respectively.
As of June 30, 2017 and December 31, 2016, the Partnership had a liability of approximately $3.6 million and $1.5 million, respectively, for non-vested phantom unit awards and associated distribution equivalent rights, which is recorded in personnel accruals and accrued expenses and other current liabilities on the Condensed Consolidated Balance Sheets.
(5) Inventories
Inventories consist primarily of domestic and foreign crude oil, blending stock and components, work-in-progress and refined fuels and by-products. For all periods presented, inventories are valued at the lower of the first-in, first-out ("FIFO") cost or net realizable value for refined fuels and by-products. Refinery unfinished and finished products inventory values were determined using the ability-to-bear process, whereby raw materials and production costs are allocated to work-in-process and finished products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of moving-average cost, which approximates FIFO, or net realizable value. The cost of inventories includes inbound freight costs.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
Inventories consisted of the following:
June 30, 2017 | December 31, 2016 | ||||||
(in millions) | |||||||
Finished goods | $ | 112.7 | $ | 135.8 | |||
Raw materials and precious metals | 82.7 | 89.7 | |||||
In-process inventories | 18.8 | 23.9 | |||||
Parts and supplies | 42.1 | 41.7 | |||||
Total Inventories | $ | 256.3 | $ | 291.1 | |||
(6) Property, Plant and Equipment
Property, plant and equipment consisted of the following:
June 30, 2017 | December 31, 2016 | ||||||
(in millions) | |||||||
Land and improvements | $ | 29.1 | $ | 29.1 | |||
Buildings | 63.3 | 47.3 | |||||
Machinery and equipment | 2,323.5 | 2,306.0 | |||||
Automotive equipment | 25.3 | 24.2 | |||||
Furniture and fixtures | 9.7 | 9.0 | |||||
Leasehold improvements | 0.8 | 0.8 | |||||
Construction in progress | 50.7 | 41.0 | |||||
2,502.4 | 2,457.4 | ||||||
Accumulated depreciation | 1,007.2 | 942.4 | |||||
Total property, plant and equipment, net | $ | 1,495.2 | $ | 1,515.0 | |||
Capitalized interest recognized as a reduction in interest expense for the three months ended June 30, 2017 and 2016 totaled approximately $0.1 million and $1.9 million, respectively. Capitalized interest recognized as a reduction in interest expense for the six months ended June 30, 2017 and 2016 totaled approximately $0.4 million and $3.4 million, respectively. Land, buildings and equipment that are under a capital lease obligation had an original carrying value of approximately $24.8 million at both June 30, 2017 and December 31, 2016. Amortization of assets held under capital leases is included in depreciation expense.
(7) Cost Classifications
Cost of materials and other includes cost of crude oil, other feedstocks, blendstocks, purchased refined products, renewable identification numbers ("RINs") and transportation and distribution costs.
Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, property taxes, environmental compliance costs as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses also include allocated share-based compensation from CVR Energy and its subsidiaries, as discussed in Note 4 ("Share-Based Compensation"). Direct operating expenses exclude depreciation and amortization of approximately $31.7 million and $30.9 million for the three months ended June 30, 2017 and 2016, respectively. For the six months ended June 30, 2017 and 2016, direct operating expenses exclude depreciation and amortization of approximately $65.0 million and $61.8 million, respectively.
Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of direct and allocated expenses for legal, treasury, accounting, marketing, human resources, information technology and maintaining the corporate and administrative offices in Texas and Kansas. Selling, general and administrative expenses also include allocated share-based compensation from CVR Energy and its subsidiaries as discussed in Note 4 ("Share-Based Compensation"). Selling, general and administrative expenses exclude depreciation and amortization of approximately $0.7 million and $0.7 million for the
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
three months ended June 30, 2017 and 2016, respectively. For the six months ended June 30, 2017 and 2016, selling, general and administrative expenses exclude depreciation and amortization of approximately $1.5 million and $1.3 million, respectively.
(8) Long-Term Debt
Long-term debt consisted of the following:
June 30, 2017 | December 31, 2016 | ||||||
(in millions) | |||||||
6.5% Senior Notes, due 2022 | $ | 500.0 | $ | 500.0 | |||
Capital lease obligations | 46.0 | 46.9 | |||||
Total debt | 546.0 | 546.9 | |||||
Unamortized debt issuance costs | (4.9 | ) | (5.4 | ) | |||
Current portion of capital lease obligations | (2.0 | ) | (1.8 | ) | |||
Long-term debt, net of current portion | $ | 539.1 | $ | 539.7 | |||
2022 Senior Notes
The Partnership has $500.0 million aggregate principal amount of 6.5% Senior Notes due 2022 (the "2022 Notes") outstanding, which were issued on October 23, 2012. The 2022 Notes were issued at par and mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013.
The 2022 Notes contain customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creation of liens on assets, the ability to dispose of assets, the ability to make certain payments on contractually subordinated debt, the ability to merge, consolidate with or into another entity and the ability to enter into certain affiliate transactions. The 2022 Notes provide that the Partnership can make distributions to holders of its common units provided, among other things, it has a minimum fixed charge coverage ratio and there is no default or event of default under the 2022 Notes. As of June 30, 2017, the Partnership was in compliance with the covenants contained in the 2022 Notes.
At June 30, 2017, the estimated fair value of the 2022 Notes was approximately $503.8 million. This estimate of fair value is Level 2 as it was determined by quotations obtained from a broker dealer who makes a market in these and similar securities.
Amended and Restated Asset Based (ABL) Credit Facility
The Partnership has a senior secured asset based revolving credit facility (the "Amended and Restated ABL Credit Facility") with an aggregate principal amount of up to $400.0 million with an incremental facility, which permits an increase in borrowings of up to $200.0 million subject to receipt of additional lender commitments and certain other conditions. The Amended and Restated ABL Credit Facility is scheduled to mature on December 20, 2017. The Partnership is considering various refinancing options in association with the Amended and Restated ABL Credit Facility maturity.
The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Partnership and its subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investments and loans, enter into affiliate transactions, issue equity interests or create subsidiaries and unrestricted subsidiaries. The Amended and Restated ABL Credit Facility also contains a fixed charge coverage ratio financial covenant, as defined therein. The Partnership was in compliance with the covenants of the Amended and Restated ABL Credit Facility as of June 30, 2017.
As of June 30, 2017, the Partnership had availability under the Amended and Restated ABL Credit Facility of $333.2 million and had letters of credit outstanding of approximately $28.4 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of June 30, 2017. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions as of June 30, 2017.
15
CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
Intercompany Credit Facility
The Partnership maintains a $250.0 million senior unsecured revolving credit facility (the "intercompany credit facility") with CRLLC as the lender, to be used to fund growth capital expenditures. The intercompany credit facility has a term of six years and bears interest at a rate of LIBOR plus 3% per annum, payable quarterly.
The intercompany credit facility contains covenants that require the Partnership to, among other things, notify CRLLC of the occurrence of any default or event of default and provide CRLLC with information in respect of the Partnership's business and financial status as it may reasonably require, including, but not limited to, copies of its unaudited quarterly financial statements and its audited annual financial statements. The Partnership was in compliance with the covenants of the intercompany credit facility as of June 30, 2017.
In addition, the intercompany credit facility contains customary events of default, including, among others, failure to pay any sum payable when due; the occurrence of a default under other indebtedness in excess of $25.0 million; and the occurrence of an event that results in either (i) CRLLC no longer directly or indirectly controlling the general partner, or (ii) CRLLC and its affiliates no longer owning a majority of the Partnership's equity interests. As of June 30, 2017, the Partnership had no borrowings outstanding and $250.0 million available under the intercompany credit facility.
Capital Lease Obligations
CVR Refining maintains two leases, accounted for as a capital lease and a financial obligation, which related to Magellan Pipeline Terminals, L.P. ("Magellan Pipeline") and Excel Pipeline LLC ("Excel Pipeline"). The underlying assets and related depreciation are included in property, plant and equipment. The capital lease, which relates to a sales-lease back agreement with Sunoco Pipeline, L.P. for its membership interest in the Excel Pipeline, has 148 months remaining of its term and will expire in September 2029. The financing arrangement, which relates to the Magellan Pipeline terminals, bulk terminal and loading facility, has 147 months remaining lease term and will expire in September 2029.
(9) Partners' Capital and Partnership Distributions
The Partnership had two types of partnership interests outstanding at June 30, 2017:
• | common units; and |
• | a general partner interest, which is not entitled to any distributions, and which is held by the general partner. |
At June 30, 2017, the Partnership had a total of 147,600,000 common units issued and outstanding, of which 97,315,764 common units were owned by CVR Refining Holdings, LLC representing approximately 66% of the total Partnership common units outstanding.
The board of directors of the Partnership's general partner has adopted a policy for the Partnership to distribute all available cash generated on a quarterly basis. Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for distribution for each quarter will be determined by the board of directors of the general partner following the end of such quarter. Available cash for distribution for each quarter will generally equal Adjusted EBITDA reduced for (i) cash needed for debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for major scheduled turnaround expenses and, (iv) to the extent applicable, reserves for future operating or capital needs that the board of directors of the general partner deems necessary or appropriate, if any. Adjusted EBITDA represents EBITDA (net income before interest expense and other financing costs, net of interest income; income tax expense; and depreciation and amortization) adjusted for (i) FIFO impact, (favorable) unfavorable, (ii) major scheduled turnaround expenses (that many of our competitors capitalize and thereby exclude from their measures of EBITDA and adjusted EBITDA), (iii) (gain) loss on derivatives, net and (iv) current period settlements on derivative contracts. Available cash for distribution may be increased by the release of previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of the general partner. The board of directors of the general partner may modify the cash distribution policy at any time, and the partnership agreement does not require the board of directors of the general partner to make distributions at all.
16
CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
(10) Net Income (Loss) per Common Unit
The Partnership's net income (loss) is allocated wholly to the common units as the general partner does not have an economic interest. Basic and diluted net income (loss) per common unit is calculated by dividing net income (loss) by the weighted-average number of common units outstanding during the period and, when applicable, giving effect to unvested common units granted under the CVR Refining LTIP. There were no dilutive awards outstanding during the three and six months ended June 30, 2017 and 2016, as all unvested awards under the CVR Refining LTIP were liability-classified awards.
The following table illustrates the Partnership's calculation of net income (loss) per common unit for the three and six months ended June 30, 2017 and 2016:
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions, except per unit data) | |||||||||||||||
Net income (loss) | $ | (19.2 | ) | $ | 78.1 | $ | 47.8 | $ | 10.1 | ||||||
Net income (loss) per common unit, basic and diluted | $ | (0.13 | ) | $ | 0.53 | $ | 0.32 | $ | 0.07 | ||||||
Weighted-average common units outstanding, basic and diluted | 147.6 | 147.6 | 147.6 | 147.6 | |||||||||||
(11) Commitments and Contingencies
Leases and Unconditional Purchase Obligations
The minimum required payments for CVR Refining's operating lease agreements and unconditional purchase obligations are as follows:
Operating Leases | Unconditional Purchase Obligations(1) | ||||||
(in millions) | |||||||
Six months ending December 31, 2017 | $ | 0.3 | $ | 78.2 | |||
Year Ending December 31, | |||||||
2018 | 0.4 | 125.5 | |||||
2019 | 0.3 | 122.1 | |||||
2020 | 0.1 | 109.6 | |||||
2021 | — | 100.4 | |||||
Thereafter | 0.2 | 651.6 | |||||
$ | 1.3 | $ | 1,187.4 | ||||
(1) | This amount includes approximately $713.5 million payable ratably over 14 years pursuant to petroleum transportation service agreements between Coffeyville Resources Refining & Marketing, LLC ("CRRM") and each of TransCanada Keystone Pipeline Limited Partnership and TransCanada Keystone Pipeline, LP (together, "TransCanada"). The purchase obligation reflects the exchange rate between the Canadian dollar and the U.S. dollar as of June 30, 2017, where applicable. Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of 20 years on TransCanada's Keystone pipeline system. |
CVR Refining leases various equipment, including real properties, under long-term operating leases expiring at various dates. For the three months ended June 30, 2017 and 2016, lease expense totaled approximately $0.1 million and $0.3 million, respectively. For the six months ended June 30, 2017 and 2016, lease expense totaled approximately $0.5 million and $0.8 million, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR Refining's option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
Additionally, in the normal course of business, CVR Refining has long-term commitments to purchase storage capacity and pipeline transportation services. For the three months ended June 30, 2017 and 2016, total expense of approximately $35.9 million and $33.1 million, respectively, was incurred related to long-term commitments. For the six months ended June 30, 2017 and 2016, total expense of approximately $73.8 million and $65.3 million, respectively, was incurred related to long-term commitments.
Crude Oil Supply Agreement
On August 31, 2012, CRRM and Vitol Inc. ("Vitol") entered into an Amended and Restated Crude Oil Supply Agreement (as amended, the "Vitol Agreement"). Under the Vitol Agreement, Vitol supplies the petroleum business with crude oil and intermediation logistics, which helps to reduce the Partnership's inventory position and mitigate crude oil pricing risk. The Vitol Agreement will automatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of any Renewal Term. The Vitol Agreement currently extends through December 31, 2018.
Litigation
From time to time, CVR Refining is involved in various lawsuits arising in the normal course of business, including matters such as those described below under "Environmental, Health and Safety ("EHS") Matters." Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. It is possible that management's estimates of the outcomes will change within the next year due to uncertainties inherent in litigation and settlement negotiations. There were no new proceedings or material developments in proceedings from those provided in the 2016 Form 10-K. In the opinion of management, the ultimate resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying condensed consolidated financial statements. There can be no assurance that management's beliefs or opinions with respect to liability for potential litigation matters will prove to be accurate.
Environmental, Health and Safety ("EHS") Matters
CVR Refining's subsidiaries are subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related to EHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potential recoveries.
Except as otherwise described below, there have been no new developments or material changes to the environmental accruals or expected capital expenditures related to compliance with the environmental matters from those provided in the 2016 Form 10-K. CVR Refining believes its subsidiaries are in material compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described or referenced herein or other EHS matters which may develop in the future will not have a material adverse effect on CVR Refining's business, financial condition or results of operations.
At June 30, 2017, CVR Refining's Condensed Consolidated Balance Sheets included total environmental accruals of $4.3 million, as compared with $4.8 million at December 31, 2016. Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.
Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended June 30, 2017 and 2016, capital expenditures were approximately $2.1 million and $2.6 million, respectively. For the six months ended June 30, 2017 and 2016, capital expenditures were approximately $6.8 million and $6.1 million, respectively. These expenditures were incurred for environmental compliance and efficiency of the operations.
RINs expense for the three months ended June 30, 2017 and 2016 was $105.6 million and $51.0 million, respectively. RINs expense for the six months ended June 30, 2017 and 2016 was $99.2 million and $94.1 million, respectively. RINs expense includes the impact of recognizing the Partnership’s uncommitted biofuel blending obligation at fair value based on market prices
18
CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
at each reporting date. As of June 30, 2017 and December 31, 2016, CVR Refining's biofuel blending obligation was approximately $279.9 million and $186.2 million, respectively, which is recorded in accrued expenses and other current liabilities in the Condensed Consolidated Balance Sheets.
(12) Fair Value Measurements
In accordance with ASC Topic 820 — Fair Value Measurements and Disclosures ("ASC 820"), the Partnership utilizes the market approach to measure fair value for its financial assets and liabilities. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities or a group of assets or liabilities, such as a business.
ASC 820 utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:
• | Level 1 — Quoted prices in active markets for identical assets or liabilities |
• | Level 2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities) |
• | Level 3 — Significant unobservable inputs (including CVR Refining's own assumptions in determining the fair value) |
The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of June 30, 2017 and December 31, 2016:
June 30, 2017 | |||||||||||||||
Location and Description | Level 1 | Level 2 | Level 3 | Total | |||||||||||
(in millions) | |||||||||||||||
Other current liabilities (biofuel blending obligation) | $ | — | $ | (273.6 | ) | $ | — | $ | (273.6 | ) | |||||
Total Liabilities | $ | — | $ | (273.6 | ) | $ | — | $ | (273.6 | ) | |||||
December 31, 2016 | |||||||||||||||
Location and Description | Level 1 | Level 2 | Level 3 | Total | |||||||||||
(in millions) | |||||||||||||||
Other current liabilities (derivative agreements) | $ | — | $ | (11.1 | ) | $ | — | $ | (11.1 | ) | |||||
Other current liabilities (biofuel blending & benzene obligations) | — | (187.0 | ) | — | (187.0 | ) | |||||||||
Total Liabilities | $ | — | $ | (198.1 | ) | $ | — | $ | (198.1 | ) | |||||
As of June 30, 2017 and December 31, 2016, the only financial assets and liabilities that are measured at fair value on a recurring basis are CVR Refining's derivative instruments, uncommitted biofuel blending obligation and benzene obligation. Additionally, the fair value of the debt issuances is disclosed in Note 8 ("Long-Term Debt"). The commodity derivative contracts, the uncommitted biofuel blending obligation and benzene obligation, which use fair value measurements and are valued using broker quoted market prices of similar instruments, are considered level 2 inputs. CVR Refining had no transfers of assets or liabilities between any of the above levels during the six months ended June 30, 2017.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
(13) Derivative Financial Instruments
Gain (loss) on derivatives, net and current period settlements on derivative contracts were as follows:
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions) | |||||||||||||||
Current period settlements on derivative contracts | $ | (0.1 | ) | $ | 7.1 | $ | 1.1 | $ | 28.5 | ||||||
Gain (loss) on derivatives, net | — | (1.9 | ) | 12.2 | (3.1 | ) | |||||||||
CVR Refining is subject to price fluctuations caused by supply conditions, weather, economic conditions, interest rate fluctuations and other factors. To manage price risk on crude oil and other inventories and to fix margins on certain future production, CVR Refining from time to time enters into various commodity derivative transactions.
CVR Refining has adopted accounting standards which impose extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. CVR Refining holds derivative instruments, such as exchange-traded crude oil futures and certain over-the-counter forward swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges for GAAP purposes. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. There are no premiums paid or received at inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts.
CVR Refining maintains a margin account to facilitate other commodity derivative activities. A portion of this account may include funds available for withdrawal. These funds are included in cash and cash equivalents within the Condensed Consolidated Balance Sheets. The maintenance margin balance is included within other current assets within the Condensed Consolidated Balance Sheets. Dependent upon the position of the open commodity derivatives, the amounts are accounted for as other current assets or other current liabilities within the Condensed Consolidated Balance Sheets. From time to time, CVR Refining may be required to deposit additional funds into this margin account. There were no open commodity positions as of June 30, 2017. For the three months ended June 30, 2017 and 2016, the Partnership recognized a net loss of $0.1 million and $0.1 million, respectively. For the six months ended June 30, 2017 and 2016, the Partnership recognized net losses of $0.2 million and $0.4 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statement of Operations.
Commodity Swaps
CVR Refining enters into commodity swap contracts in order to fix the margin on a portion of future production. Additionally, CVR Refining may enter into price and basis swaps in order to fix the price on a portion of its commodity purchases and product sales. The physical volumes are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Condensed Consolidated Balance Sheets with changes in fair value currently recognized in the Condensed Consolidated Statements of Operations. Quoted prices for similar assets or liabilities in active markets (Level 2) are considered to determine the fair values for the purpose of marking to market the hedging instruments at each period end. At December 31, 2016, CVR Refining had open commodity swap instruments consisting of 4.0 million barrels of crack spreads, primarily to fix the margin on a portion of its future gasoline and distillate production. At June 30, 2017, the Partnership had no open commodity swap instruments. For the three months ended June 30, 2017 and 2016, CVR Refining recognized a net gain of $0.1 million and a net loss of $1.8 million, respectively. For the six months ended June 30, 2017 and 2016, CVR Refining recognized a net gain of $12.4 million and a net loss of $2.7 million, respectively. These recognized gains and losses are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.
Counterparty Credit Risk
CVR Refining's exchange-traded crude oil futures and certain over-the-counter forward swap agreements are potentially exposed to concentrations of credit risk as a result of economic conditions and periods of uncertainty and illiquidity in the credit and capital markets. CVR Refining manages credit risk on its exchange-traded crude oil futures by completing trades with an exchange clearinghouse, which subjects the trades to mandatory margin requirements until the contract settles. CVR Refining also
20
CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
monitors the creditworthiness of its commodity swap counterparties and assesses the risk of nonperformance on a quarterly basis. Counterparty credit risk identified as a result of this assessment is recognized as a valuation adjustment to the fair value of the commodity swaps recorded in the Condensed Consolidated Balance Sheets. As of June 30, 2017, the Partnership had no open commodity swaps. Additionally, CVR Refining does not require any collateral to support commodity swaps into which it enters; however, it does have master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party, which mitigates the risk associated with nonperformance.
Offsetting Assets and Liabilities
The commodity swaps and other commodity derivatives agreements discussed above include multiple derivative positions with a number of counterparties for which CVR Refining has entered into agreements governing the nature of the derivative transactions. Each of the counterparty agreements provides for the right to setoff each individual derivative position to arrive at the net receivable due from the counterparty or payable owed by CVR Refining. As a result of the right to setoff, CVR Refining's recognized assets and liabilities associated with the outstanding derivative positions have been presented net in the Condensed Consolidated Balance Sheets. In accordance with guidance issued by the FASB related to "Disclosures about Offsetting Assets and Liabilities," the table below outlines the gross amounts of the recognized assets and liabilities and the gross amounts offset in the Condensed Consolidated Balance Sheets for the various types of open derivative positions. There were no open commodity swap instruments as of June 30, 2017.
The offsetting assets and liabilities for CVR Refining's derivatives as of December 31, 2016 are recorded as current assets and current liabilities in prepaid expenses and other current assets and accrued expenses and other current liabilities, respectively, in the Condensed Consolidated Balance Sheets as follows:
As of December 31, 2016 | |||||||||||||||||||
Description | Gross Current Liabilities | Gross Amounts Offset | Net Current Liabilities Presented | Cash Collateral Not Offset | Net Amount | ||||||||||||||
(in millions) | |||||||||||||||||||
Commodity Swaps | $ | 11.1 | $ | — | $ | 11.1 | $ | — | $ | 11.1 | |||||||||
Total | $ | 11.1 | $ | — | $ | 11.1 | $ | — | $ | 11.1 | |||||||||
(14) Related Party Transactions
CVR Refining is party to, or otherwise subject to certain agreements with CVR Energy and its subsidiaries (including CVR Partners, LP and its subsidiary, Coffeyville Resources Nitrogen Fertilizer, LLC ("CRNF")) that govern the business relations among each party including: the (i) Feedstock and Shared Services Agreement; (ii) Coke Supply Agreement; (iii) Hydrogen Purchase and Sales Agreement; (iv) Environmental Agreement; (v) Services Agreement and (vi) Limited Partnership Agreement. The agreements are described as in effect at June 30, 2017. Except as otherwise described below, there have been no new developments or material changes to these agreements from those provided in the 2016 Form 10-K.
Amounts owed to CVR Refining and CRRM from CVR Energy and its subsidiaries with respect to these agreements are included in accounts receivable and prepaid expenses and other current assets on the Condensed Consolidated Balance Sheets. Conversely, amounts owed to CVR Energy and its subsidiaries by CVR Refining and CRRM with respect to these agreements are included in accounts payable, personnel accruals, accrued expenses and other current liabilities, and other long-term liabilities, on CVR Refining's Condensed Consolidated Balance Sheets.
Feedstock and Shared Services Agreement
CRRM is party to a feedstock and shared services agreement with CRNF, under which the two parties provide feedstocks and other services to one another. These feedstocks and services are utilized in the respective production processes of CRRM's Coffeyville, Kansas refinery and CRNF's Coffeyville, Kansas nitrogen fertilizer plant. Feedstocks provided under the agreement include, among others, hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas. The agreement was amended and restated effective January 1, 2017.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
Prior to January 1, 2017, CRRM and CRNF transferred hydrogen to one another pursuant to the feedstock and shared services agreement. Net monthly sales of hydrogen to CRNF have been reflected as net sales for CVR Refining, when applicable. Net monthly receipts of hydrogen from CRNF have been reflected in cost of materials and other for CVR Refining. For the three months ended June 30, 2016, CVR Refining recognized $0.5 million of cost of materials and other related to the net purchases of hydrogen from the Coffeyville fertilizer facility. For the six months ended June 30, 2016, CVR Refining recognized $1.6 million of cost of materials and other related to the net purchases of hydrogen from the Coffeyville fertilizer facility. At December 31, 2016, there was approximately $0.1 million of accounts receivable included in prepaid expenses and other current assets on the Consolidated Balance Sheet associated with net hydrogen sales.
Beginning January 1, 2017, hydrogen sales to CRNF are governed pursuant to the hydrogen purchase and sales agreement discussed below, but hydrogen purchases from CRNF remain governed pursuant to the feedstock and shared services agreement. For the three and six months ended June 30, 2017, the gross purchases of hydrogen from CRNF pursuant to the feedstock and shared services agreement were approximately $0.0 million and $0.1 million, respectively, and were included in cost of materials and other in the Condensed Consolidated Statements of Operations. The monthly hydrogen purchases are cash settled net on a monthly basis with hydrogen sales, pursuant to the hydrogen purchase and sale agreement.
The feedstock and shared services agreement also provides a mechanism pursuant to which CRNF transfers a tail gas stream to CRRM. For each of the three and six months ended June 30, 2017 and 2016, direct operating expenses generated by the purchase of tail gas from CRNF were nominal. In April 2011, in connection with the tail gas stream, CRRM installed a pipe between the Coffeyville, Kansas refinery and the nitrogen fertilizer plant to transfer the tail gas. CRNF agreed to pay CRRM the cost of installing the pipe and provided an additional 15% to cover the cost of capital, which was due from CRNF to CRRM over four years. At June 30, 2017 and December 31, 2016, a liability of approximately $0.2 million and $0.2 million, respectively, was included in other current liabilities and approximately $0.5 million and $0.6 million, respectively, was included in other non-current liabilities in the Condensed Consolidated Balance Sheets.
At June 30, 2017 and December 31, 2016, payables of a nominal amount and $0.3 million, respectively, were included in accounts payable on the Condensed Consolidated Balance Sheets associated with amounts yet to be paid related to components of the feedstock and shared services agreement, other than amounts associated with hydrogen purchases and tail gas discussed above. At both June 30, 2017 and December 31, 2016, receivables of approximately $0.9 million were included in prepaid expenses and other current assets on the Condensed Consolidated Balance Sheets associated with receivables related to components of the feedstock and shared services agreement.
Hydrogen Purchase and Sale Agreement
CRRM and CRNF entered into a hydrogen purchase and sale agreement that was effective on January 1, 2017, pursuant to which CRRM agrees to sell and deliver a committed hydrogen volume of 90,000 mscf per month, and CRNF agrees to purchase and receive the committed volume. The committed volume pricing is based on a monthly fixed fee (based on the fixed and capital charges associated with producing the committed volume) and a monthly variable fee (based on the natural gas price associated with hydrogen actually received). In the event CRNF fails to take delivery of the full committed volume in a month, CRNF remains obligated to pay CRRM for the monthly fixed fee and a monthly variable fee based upon the actual hydrogen volume received, if any. In the event CRRM fails to deliver any portion of the committed volume for the applicable month for any reason other than planned repairs and maintenance, CRNF will be entitled to a pro-rata reduction of the monthly fixed fee. CRNF also has the option to purchase excess volume of up to 60,000 mscf per month, or more upon mutual agreement, from CRRM, if available for purchase.
A portion of the monthly variable fee, as defined in the terms of the agreement, is determined according to the natural gas costs incurred by CRRM in operation of the hydrogen plant, which will reflect market-driven changes in the natural gas prices. In addition, certain fixed fees will be adjusted on an annual basis according to the changes in a cost index, as defined in the terms of the agreement.
CRRM is not required to sell hydrogen to CRNF if such sale would adversely affect CVR Refining’s classification as a partnership for federal income tax purposes, and is not required to sell hydrogen to CRNF in excess of the committed volume if such volumes are needed for CRRM’s operations.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
The agreement has an initial term of 20 years and will be automatically extended following the initial term for additional successive five-year renewal terms unless either party gives 180 days written notice. Certain fees under the agreement are subject to modification after this initial term. The agreement contains customary terms related to indemnification, as well as termination for breach, by mutual consent, or due to insolvency or cessation of operations.
For the three and six months ended June 30, 2017, the gross sales of hydrogen to CRNF were approximately $0.9 million and $2.1 million, respectively. The monthly hydrogen sales are cash settled net with hydrogen purchases pursuant to the feedstock and shared services agreement. At June 30, 2017, approximately $0.3 million was included in accounts receivables on the Condensed Consolidated Balance Sheets associated with the net hydrogen sales to CRNF.
Coke Supply Agreement
CRRM is party to a coke supply agreement with CRNF pursuant to which CRRM supplies CRNF with pet coke. This agreement provides that CRRM must deliver to CRNF during each calendar year an annual required amount of pet coke equal to the lesser of (i) 100 percent of the pet coke produced at CRRM's Coffeyville, Kansas petroleum refinery or (ii) 500,000 tons of pet coke. CRNF is also obligated to purchase this annual required amount. If during a calendar month CRRM produces more than 41,667 tons of pet coke, then CRNF will have the option to purchase the excess at the purchase price provided for in the agreement. If CRNF declines to exercise this option, CRRM may sell the excess to a third party.
The price CRNF pays pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received for urea ammonium nitrate ("UAN") (the "UAN-based price") or a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN that excludes transportation cost ("netback price") of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton.
CRNF pays any taxes associated with the sale, purchase, transportation, delivery, storage or consumption of the pet coke and is entitled to offset any amount payable for the pet coke against any amount due from CRRM under the feedstock and shared services agreement between the parties.
Net sales associated with the transfer of pet coke from CRRM to CRNF were approximately $0.8 million and $0.5 million for the three months ended June 30, 2017 and 2016, respectively. Net sales associated with the transfer of pet coke from CRRM to CRNF were approximately $1.2 million and $0.9 million for the six months ended June 30, 2017 and 2016, respectively. Receivables of $0.1 million related to the coke supply agreement were included in accounts receivable on the Condensed Consolidated Balance Sheets at December 31, 2016 and $0.3 million was included in accounts receivable at June 30, 2017.
Services Agreement
CVR Refining obtains certain management and other services from CVR Energy pursuant to a services agreement between the Partnership, CVR Refining GP and CVR Energy. Net amounts incurred under the services agreement for the three and six months ended June 30, 2017 and 2016 were as follows:
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions) | |||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | $ | 2.4 | $ | 3.4 | $ | 5.4 | $ | 6.3 | |||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 12.4 | 12.0 | 24.5 | 24.6 | |||||||||||
Total | $ | 14.8 | $ | 15.4 | $ | 29.9 | $ | 30.9 | |||||||
At June 30, 2017 and December 31, 2016, payables and liabilities of approximately $9.9 million and $11.9 million, respectively, were included in accounts payable, personnel accruals and accrued expenses and other current liabilities on the Condensed Consolidated Balance Sheets with respect to amounts billed in accordance with the services agreement.
23
CVR REFINING, LP AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2017
(unaudited)
Limited Partnership Agreement
The partnership agreement provides that the Partnership will reimburse its general partner for all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership (including salary, bonus, incentive compensation and other amounts paid to any person to perform services for the Partnership or for its general partner in connection with operating the Partnership). For the three months ended June 30, 2017 and 2016, approximately $2.0 million and $1.5 million, respectively, were incurred under the partnership agreement. For the six months ended June 30, 2017 and 2016, approximately $4.2 million and $3.4 million, respectively, were incurred under the partnership agreement.
Intercompany Credit Facility
The Partnership has an intercompany credit facility with CRLLC with a borrowing capacity of $250.0 million. As of June 30, 2017, the Partnership had no borrowings outstanding under the intercompany credit facility. For the three months ended June 30, 2017 and 2016, the Partnership paid $0.0 million and $0.3 million, respectively, of interest to CRLLC. For the six months ended June 30, 2017 and 2016, the Partnership paid $0.0 million and $0.6 million, respectively, of interest to CRLLC. See Note 8 ("Long-Term Debt") for additional discussion of the intercompany credit facility.
Insight Portfolio Group
Insight Portfolio Group LLC ("Insight Portfolio Group") is an entity formed by Mr. Carl C. Icahn in order to maximize the potential buying power of a group of entities with which Mr. Icahn has a relationship in negotiating with a wide range of suppliers of goods, services and tangible and intangible property at negotiated rates. In January 2013, CVR Energy acquired a minority equity interest in Insight Portfolio Group. The Partnership participates in Insight Portfolio Group's buying group through its relationship with CVR Energy. The Partnership may purchase a variety of goods and services as members of the buying group at prices and on terms that management believes would be more favorable than those which would be achieved on a stand-alone basis.
Joint Venture Agreement
The Partnership holds a 40% interest in a joint venture, Velocity Pipeline Partners, LLC, and the joint venture provides the Partnership with crude oil transportation services. See Note 15 ("Equity Method Investment") for additional discussion of the joint venture.
(15) Equity Method Investment
On September 19, 2016, Coffeyville Resources Pipeline, LLC ("CRPLLC"), an indirect wholly-owned subsidiary of CVR Refining, entered into an agreement with Velocity Central Oklahoma Pipeline LLC ("Velocity") related to their joint ownership of Velocity Pipeline Partners, LLC ("VPP"), which was formed to construct, own and operate a crude oil pipeline. CRPLLC holds a 40% interest in VPP. Velocity holds a 60% interest in VPP and serves as the day-to-day operator of VPP. As of June 30, 2017, the carrying value of CRPLLC's investment in VPP was $7.1 million, which is recorded in other long-term assets on the Condensed Consolidated Balance Sheets. Contributions by CRPLLC to VPP during the pipeline construction totaled $7.0 million, of which $1.4 million was contributed in the first quarter of 2017.
The pipeline commenced operations in mid-April 2017 following completion of construction. Equity income from VPP for the three months ended June 30, 2017 was $0.1 million, which is recorded in other income (expense), net on the Condensed Consolidated Statement of Operations. In July 2017, CRPLLC received a cash distribution from VPP of $0.9 million.
CRRM is party to a transportation agreement with VPP pursuant to which VPP provides transportations services to CRRM for crude oil shipped on VPP's pipeline. For the three months ended June 30, 2017, CRRM incurred costs of $0.5 million under the transportation agreement with VPP. As of June 30, 2017, the Condensed Consolidated Balance Sheet included a liability of $0.3 million to VPP.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and related notes and with the statistical information and financial data appearing in this Report, as well as our 2016 Form 10-K. Results of operations and cash flows for the three and six months ended June 30, 2017 are not necessarily indicative of results to be attained for any other period.
Forward-Looking Statements
This Report, including this Management's Discussion and Analysis of Financial Condition and Results of Operations, contains "forward-looking statements" as defined by the Securities and Exchange Commission ("SEC"), including statements concerning contemplated transactions and strategic plans, expectations and objectives for future operations. Forward-looking statements include, without limitation:
• | statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future; |
• | statements relating to future financial or operational performance, future distributions, future capital sources and capital expenditures; and |
• | any other statements preceded by, followed by or that include the words "anticipates," "believes," "expects," "plans," "intends," "estimates," "projects," "could," "should," "may" or similar expressions. |
Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report, including this Management's Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements as a result of various factors, including but not limited to those set forth under Part I — Item 1A. "Risk Factors" in the 2016 Form 10-K. Such factors include, among others:
• | our ability to make cash distributions on the common units; |
• | the price volatility of crude oil, other feedstocks and refined products, and variable nature of our distributions; |
• | the ability of our general partner to modify or revoke our distribution policy at any time; |
• | our ability to forecast our future financial condition or results of operations and our future revenues and expenses; |
• | the effects of transactions involving forward and derivative instruments; |
• | our ability in the future to obtain an adequate crude oil supply pursuant to supply agreements or at all; |
• | our continued access to crude oil and other feedstock and refined products pipelines; |
• | the level of competition from other petroleum refiners; |
• | changes in our credit profile; |
• | potential operating consequences from accidents, fire, severe weather, floods, or other natural disasters, or other operating hazards resulting in unscheduled downtime; |
• | our continued ability to secure RINs, as well as environmental and other governmental permits necessary for the operation of our business; |
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• | costs of compliance with existing, or compliance with new, environmental laws and regulations, as well as the potential liabilities arising from, and capital expenditures required to, remediate current or future contamination; |
• | the seasonal nature of our business; |
• | our dependence on significant customers; |
• | our potential inability to obtain or renew permits; |
• | our ability to continue safe, reliable operations without unplanned maintenance events prior to and when approaching the end-of-cycle turnaround operations; |
• | new regulations concerning the transportation of hazardous chemicals, risks of terrorism, and the security of chemical manufacturing facilities; |
• | the risk of security breaches; |
• | our lack of asset diversification; |
• | the potential loss of our transportation cost advantage over our competitors; |
• | our ability to comply with employee safety laws and regulations; |
• | potential disruptions in the global or U.S. capital and credit markets; |
• | the success of our acquisition and expansion strategies; |
• | our reliance on CVR Energy's senior management team; |
• | the risk of a substantial increase in costs or work stoppages associated with negotiating collective bargaining agreements with the unionized portion of our workforce; |
• | the potential shortage of skilled labor or loss of key personnel; |
• | successfully defending against third-party claims of intellectual property infringement; |
• | our indebtedness; |
• | our potential inability to generate sufficient cash to service all of our indebtedness; |
• | the limitations contained in our debt agreements that limit our flexibility in operating our business; |
• | the dependence on our subsidiaries for cash to meet our debt obligations; |
• | our limited operating history as a stand-alone entity; |
• | potential increases in costs and distraction of management resulting from the requirements of being a publicly traded partnership; |
• | exemptions we will rely on in connection with the NYSE corporate governance requirements; |
• | risks relating to our relationships with CVR Energy; |
• | risks relating to the control of our general partner by CVR Energy; |
• | the conflicts of interest faced by our senior management team, which operates both us and CVR Energy, and our general partner; |
• | limitations on duties owed by our general partner that are included in the partnership agreement; |
• | changes in our treatment as a partnership for U.S. income or state tax purposes; and |
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• | instability and volatility in the capital and credit markets. |
All forward-looking statements contained in this Report only speak as of the date of this Report. We undertake no obligation to publicly update or revise any forward-looking statements to reflect events or circumstances that occur after the date of this Report, or to reflect the occurrence of unanticipated events, except to the extent required by law.
Partnership Overview
We are an independent downstream energy limited partnership with refining and related logistics assets that operates in Group 3 of the PADD II region of the United States. Our business includes a complex full coking medium-sour crude oil refinery in Coffeyville, Kansas with a rated capacity of 115,000 bpcd and a complex crude oil refinery in Wynnewood, Oklahoma with a rated capacity of 70,000 bpcd capable of processing 20,000 bpcd of light sour crude oils (within its rated capacity of 70,000 bpcd). In addition, our supporting businesses include (i) a crude oil gathering system with a gathering capacity of over 70,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri, Colorado and Texas, which serves our two refineries, (ii) a 170,000 bpd pipeline system, which transports crude oil to our Coffeyville refinery from our Broome Station facility located near Caney, Kansas, and is supported by approximately 340 miles of active owned and leased pipelines, (iii) a 65,000 bpd pipeline owned and operated by our joint venture VPP, which transports gathered crude oil to our Wynnewood refinery from a trucking terminal at Lowrance, Oklahoma, (iv) approximately 6.4 million barrels of owned and leased crude oil storage, (v) a rack marketing business supplying refined petroleum product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and located at throughput terminals on Magellan and NuStar refined petroleum products distribution systems and (vi) over 4.5 million barrels of combined refined products and feedstocks storage capacity.
Our Coffeyville refinery is situated approximately 100 miles northeast of Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States. Our Wynnewood refinery is approximately 130 miles southwest of Cushing. Cushing is supplied by numerous pipelines from U.S. domestic locations and Canada. In addition to rack sales (sales which are made at terminals into third-party tanker trucks), we make bulk sales (sales through third-party pipelines) into the mid-continent markets and other destinations utilizing the product pipeline networks owned by Magellan and NuStar.
Crude oil is supplied to our Coffeyville refinery through our gathering system and by a pipeline owned by Plains All American Pipeline, L.P. that runs from Cushing to our Broome Station facility. We maintain capacity on the Keystone and Spearhead pipelines from Canada to Cushing. We also have contracted capacity on the Pony Express and White Cliffs pipelines, which originate in Colorado and extend to Cushing. We also maintain leased and owned storage in Cushing to facilitate optimal crude oil purchasing and blending. Crude oil is supplied to our Wynnewood refinery through three third-party pipelines operated by Sunoco Pipeline, Excel Pipeline and Blueknight Pipeline and, beginning in April 2017, through the joint venture VPP pipeline. Historically the crude has been sourced from Texas and Oklahoma. The access to a variety of crude oils coupled with the complexity of our refineries typically allows us to purchase crude oil at a discount to WTI. The consumed crude oil cost discount to WTI for the second quarter of 2017 was $0.05 per barrel compared to a discount of $3.07 per barrel in the second quarter of 2016.
Major Influences on Results of Operations
Our earnings and cash flows are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks that are processed and blended into refined products. The cost to acquire feedstocks and the price for which refined products are ultimately sold depend on factors beyond our control, including the supply of and demand for crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. Because we apply first-in, first-out ("FIFO") accounting to value our inventory, crude oil price movements may impact net income in the short term because of changes in the value of our unhedged on-hand inventory. The effect of changes in crude oil prices on our results of operations is influenced by the rate at which the prices of refined products adjust to reflect these changes.
The prices of crude oil and other feedstocks and refined products are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. Widespread expansion or upgrades of our competitors' facilities, price volatility, international political and economic developments and other factors are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market,
27
resulting in price volatility and a reduction in product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for volatile seasonal exports of diesel from the USGC markets. In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations and increased mileage standards for vehicles. We are also subject to the RFS, which requires us to either blend "renewable fuels" in with our transportation fuels or purchase RINs, in lieu of blending, by March 31, 2018 or otherwise be subject to penalties.
On December 12, 2016, the United States Environmental Protection Agency ("EPA") published in the Federal Register the final rule establishing the renewable fuel volume mandates for 2017, and the biomass-based diesel mandate for 2018. On July 21, 2017, the EPA published in the Federal Register its proposed rule establishing the renewable fuel volume mandates for 2018, and the biomass-based diesel mandate for 2019. The EPA is required by the Clean Air Act to publish the final rule for 2018 by November 30, 2017.
RINs expense for the three months ended June 30, 2017 and 2016 was $105.6 million and $51.0 million, respectively. RINs expense for the six months ended June 30, 2017 and 2016 was $99.2 million and $94.1 million, respectively. RINs expense includes the impact of recognizing the Partnership’s uncommitted biofuel blending obligation at fair value based on market prices at each reporting date. The price of RINs has been extremely volatile over the last year. The future cost of RINs is difficult to estimate. Additionally, the cost of RINs is dependent upon a variety of factors, which include EPA regulations, the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of our petroleum products, as well as the fuel blending performed at our refineries and downstream terminals, all of which can vary significantly from period to period. Based upon recent market prices of RINs and current estimates related to the other variable factors, the petroleum business currently estimates that the total cost of RINs will be approximately $200.0 million to $250.0 million for the year ending December 31, 2017.
If sufficient RINs are unavailable for purchase at times when we seek to purchase RINs, if we have to pay a significantly higher price for RINs or if we are otherwise unable to meet the EPA’s RFS mandates, our business, financial condition and results of operations could be materially adversely affected.
In order to assess our operating performance, we compare our net sales, less cost of materials and other, or our refining margin, against an industry refining margin benchmark. The industry refining margin benchmark is calculated by assuming that two barrels of benchmark light sweet crude oil are converted into one barrel of conventional gasoline and one barrel of distillate. This benchmark is referred to as the 2-1-1 crack spread. Because we calculate the benchmark margin using the market value of NYMEX gasoline and heating oil against the market value of NYMEX WTI, we refer to the benchmark as the NYMEX 2-1-1 crack spread, or simply, the 2-1-1 crack spread. The 2-1-1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude oil refinery would earn assuming it produced and sold the benchmark production of gasoline and distillate.
Although the 2-1-1 crack spread is a benchmark for our refining margin, because our refineries have certain feedstock costs and logistical advantages as compared to a benchmark refinery and our product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect refining margin. Our Coffeyville refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has historically cost less than WTI. Our Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil, although isobutane, gasoline components and normal butane are also typically used. We measure the cost advantage of our crude oil slate by calculating the spread between the price of our delivered crude oil and the price of WTI. The spread is referred to as our consumed crude oil differential. Our refining margin can be impacted significantly by the consumed crude oil differential. Our consumed crude oil differential will move directionally with changes in the WCS price differential to WTI as this differential indicates the relative price of heavier, more sour, crude oil slate to WTI. The correlation between our consumed crude oil differential and published differentials will vary depending on the volume of heavy sour crude oil we purchase as a percent of our total crude oil volume.
We produce a high volume of high value products, such as gasoline and distillates. The fact that the actual product specifications used to determine the NYMEX 2-1-1 crack spread are different from the actual production in our refineries is because the prices we realize are different than those used in determining the 2-1-1 crack spread. The difference between our price and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and Ultra-Low Sulfur Diesel PADD II, Group 3 vs. NYMEX basis, or Ultra-Low Sulfur Diesel basis. If both gasoline and Ultra-Low Sulfur Diesel basis are greater than zero, this means that prices in our marketing area exceed those used in the 2-1-1 crack spread.
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We are significantly affected by developments in the markets in which we operate. For example, numerous pipeline expansions in recent years expanding the connectivity of Cushing and Permian Basin markets to the gulf coast along with lifting the crude oil export ban has resulted in a decrease in the domestic crude advantage. The refining industry is directly impacted by these events and has seen a downward movement in refining margins as a result. The stabilization of oil prices led by OPEC's decision to lower production volumes and the resurgent shale drilling in the Permian and other tight oil plays are expected to cause price spread volatility as the industry attempts to match infrastructure to supply.
Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor and environmental compliance. Our predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the six months ended June 30, 2017, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $6.3 million.
Because crude oil and other feedstocks and refined products are commodities, we have no control over the changing market. Therefore, the lower target inventory we are able to maintain significantly reduces the impact of commodity price volatility on our earnings. Because most of our titled inventory is valued under the FIFO costing method, price fluctuations on our target level of titled inventory may have a major effect on our financial results from period to period.
Safe and reliable operations at our refineries are key to our financial performance and results of operations. Unscheduled downtime at our refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of scheduled downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. Our refineries generally require a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. The first phase of the Coffeyville refinery’s most recent turnaround was completed in November 2015. The second phase of the Coffeyville turnaround was completed during the first quarter of 2016. During the first half of 2016, we incurred $31.5 million of major scheduled turnaround expenses for the Coffeyville refinery turnaround. The next turnaround scheduled for the Wynnewood refinery will be performed as a two phase turnaround. The first phase is scheduled to begin in late September 2017 and is expected to approximate 42 days. Turnaround expenses associated with the first phase of the Wynnewood turnaround are estimated to be approximately $70.0 million. The second phase of the Wynnewood turnaround is expected to begin in the second half of 2018. In addition to the two phase turnaround, we accelerated certain planned turnaround activities in the first quarter of 2017 on the hydrocracker unit for a catalyst change-out. We incurred approximately $13.0 million of major scheduled turnaround expenses for the hydrocracker.
Agreements with Affiliates
CVR Energy and its subsidiaries are party to several agreements with CVR Partners and its subsidiary that govern the business relations among CVR Partners, CVR Energy and their subsidiaries and affiliates, and the general partner of CVR Partners. In connection with our initial public offering in January 2013, some of the subsidiaries party to these agreements became subsidiaries of CVR Refining.
These intercompany agreements include (i) the pet coke supply agreement under which CVR Partners purchases the pet coke we generate at our Coffeyville refinery for use in CVR Partners' manufacture of nitrogen fertilizer; (ii) a feedstock and shared services agreement, which governs the provision of feedstocks, including, but not limited to, hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; (iii) a raw water and facilities sharing agreement, which allocates raw water resources between the Coffeyville refinery and the nitrogen fertilizer plant; (iv) a lease agreement, pursuant to which we lease office and laboratory space to CVR Partners; (v) a cross-easement agreement, which grants easements to both parties for operational facilities, pipelines, equipment, access, and water rights; (vi) a hydrogen purchase and sale agreement; and (vii) an environmental agreement which provides for certain indemnification and access rights in connection with environmental matters affecting the Coffeyville refinery and the nitrogen fertilizer plant. These agreements were not the result of arm's-length negotiations and the terms of these agreements are not necessarily as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties.
We are also party to a number of agreements with CVR Energy and its subsidiaries, including (i) the intercompany credit facility and (ii) a services agreement, pursuant to which we obtain certain management and other services from CVR Energy.
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CRRM and Coffeyville Resources Nitrogen Fertilizers, LLC ("CRNF") entered into a hydrogen purchase and sale agreement that was effective on January 1, 2017, pursuant to which CRRM agrees to sell and deliver a committed hydrogen volume of 90,000 mscf per month, and CRNF agrees to purchase and receive the committed volume. CRNF also has the option to purchase excess volume of up to 60,000 mscf per month, or more upon mutual agreement, from CRRM, if available for purchase and priced pursuant to the agreement. The agreement has an initial term of 20 years and will be automatically extended following the initial term for additional successive five-year renewal terms unless either party gives 180 days written notice. Refer to Part I, Item 1, Note 14 ("Related Party Transactions") of this Report for further discussion of the hydrogen purchase and sale agreement.
On September 19, 2016, CRPLLC, an indirect wholly-owned subsidiary of CVR Refining, entered into an agreement with Velocity related to their joint ownership of VPP. VPP constructed, owns and operates a 12-inch crude oil pipeline with design capacity of approximately 65,000 barrel per day and with an estimated length of 25 miles with a connection to the Partnership's Wynnewood refinery and a trucking terminal at Lowrance, Oklahoma. CRPLLC holds a 40% interest in VPP and has contributed a total of $7.0 million to VPP during the pipeline construction, which was completed in April of 2017. Velocity holds a 60% interest in VPP, serves as the day-to-day operator of VPP and has contributed a total of $10.5 million to VPP. On September 19, 2016, the Partnership also entered into a transportation agreement with VPP for an initial term of 20 years under which VPP provides the Partnership with crude oil transportation services for crude oil purchased within a defined geographic area, and the Partnership entered into a terminalling services agreement with Velocity under which the Partnership receives access to Velocity’s terminal in Lowrance, Oklahoma to unload and pump crude oil into VPP's pipeline for an initial term of 20 years. The pipeline commenced operations in mid-April 2017 following completion of construction.
Crude Oil Supply Agreement
On August 31, 2012, CRRM and Vitol entered into the Vitol Agreement. Under the Vitol Agreement, Vitol supplies us with crude oil and intermediation logistics, which helps us to reduce our inventory position and mitigate crude oil pricing risk. The Vitol Agreement will automatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of any Renewal Term. The Vitol Agreement currently extends through December 31, 2018.
Results of Operations
The period to period comparisons of our results of operations have been prepared using the historical periods included in our condensed consolidated financial statements. The following tables below provide an overview of the results of operations, relevant market indicators and key operating statistics for CVR Refining and our subsidiaries for the three and six months ended June 30, 2017 and 2016. The following data should be read in conjunction with our condensed consolidated financial statements and the notes thereto included elsewhere in this Report. All information in "Management's Discussion and Analysis of Financial Condition and Results of Operations," except for the balance sheet data as of December 31, 2016, is unaudited.
Net sales consist principally of sales of refined fuel, and are mainly affected by crude oil and refined product prices, changes to the input mix and volume changes caused by operations. Product mix refers to the percentage of production represented by higher value light products, such as gasoline, versus lower value finished products, such as pet coke.
Industry-wide petroleum results are driven and measured by the relationship, or margin, between refined products and the prices for crude oil referred to as crack spreads. See "—Major Influences on Results of Operations." We discuss our results of petroleum operations in the context of per barrel consumed crack spreads and the relationship between net sales and cost of materials and other. Refining margin is a measurement calculated as the difference between net sales and cost of materials and other.
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Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions) | |||||||||||||||
Consolidated Statements of Operations Data | |||||||||||||||
Net sales | $ | 1,338.2 | $ | 1,164.4 | $ | 2,761.7 | $ | 1,998.4 | |||||||
Operating costs and expenses: | |||||||||||||||
Cost of materials and other | 1,208.0 | 941.9 | 2,409.3 | 1,664.2 | |||||||||||
Direct operating expenses(1)(2) | 83.5 | 81.9 | 172.7 | 170.2 | |||||||||||
Major scheduled turnaround expenses | 2.8 | 2.1 | 15.7 | 31.5 | |||||||||||
Depreciation and amortization | 31.7 | 30.9 | 65.0 | 61.8 | |||||||||||
Cost of sales | 1,326.0 | 1,056.8 | 2,662.7 | 1,927.7 | |||||||||||
Selling, general and administrative expenses(1) | 18.9 | 16.8 | 38.9 | 35.3 | |||||||||||
Depreciation and amortization | 0.7 | 0.7 | 1.5 | 1.3 | |||||||||||
Operating income (loss) | (7.4 | ) | 90.1 | 58.6 | 34.1 | ||||||||||
Interest expense and other financing costs | (12.0 | ) | (10.1 | ) | (23.2 | ) | (20.9 | ) | |||||||
Interest income | 0.2 | — | 0.2 | — | |||||||||||
Gain (loss) on derivatives, net | — | (1.9 | ) | 12.2 | (3.1 | ) | |||||||||
Other income (expense), net | — | — | — | — | |||||||||||
Income (loss) before income tax expense | (19.2 | ) | 78.1 | 47.8 | 10.1 | ||||||||||
Income tax expense | — | — | — | — | |||||||||||
Net income (loss) | $ | (19.2 | ) | $ | 78.1 | $ | 47.8 | $ | 10.1 | ||||||
Gross profit(3) | $ | 12.2 | $ | 107.6 | $ | 99.0 | $ | 70.7 | |||||||
Refining margin(4) | $ | 130.2 | $ | 222.5 | $ | 352.4 | $ | 334.2 | |||||||
Adjusted EBITDA(5) | $ | 43.1 | $ | 84.7 | $ | 157.6 | $ | 119.8 | |||||||
Available cash for distribution(6) | $ | — | $ | — | $ | — | $ | — | |||||||
As of June 30, 2017 | As of December 31, 2016 | ||||||
(audited) | |||||||
(in millions) | |||||||
Balance Sheet Data | |||||||
Cash and cash equivalents | $ | 515.7 | $ | 314.1 | |||
Working capital | 380.4 | 313.7 | |||||
Total assets | 2,447.1 | 2,331.9 | |||||
Total debt, including current portion | 541.1 | 541.5 | |||||
Total partners' capital | 1,344.5 | 1,296.7 | |||||
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Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions) | |||||||||||||||
Cash Flow Data | |||||||||||||||
Net cash flow provided by (used in): | |||||||||||||||
Operating activities | $ | 135.2 | $ | 37.8 | $ | 251.3 | $ | 40.8 | |||||||
Investing activities | (27.8 | ) | (24.0 | ) | (48.8 | ) | (68.0 | ) | |||||||
Financing activities | (0.5 | ) | (0.4 | ) | (0.9 | ) | (0.8 | ) | |||||||
Net cash flow | $ | 106.9 | $ | 13.4 | $ | 201.6 | $ | (28.0 | ) | ||||||
Capital expenditures for property, plant and equipment | $ | 27.8 | $ | 24.0 | $ | 47.4 | $ | 68.0 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(dollars per barrel) | |||||||||||||||
Key Operating Statistics | |||||||||||||||
Per crude oil throughput barrel: | |||||||||||||||
Gross profit(3) | $ | 0.63 | $ | 5.84 | $ | 2.56 | $ | 2.01 | |||||||
Refining margin(4) | $ | 6.69 | $ | 12.07 | $ | 9.10 | $ | 9.50 | |||||||
FIFO impact, (favorable) unfavorable | $ | 0.79 | $ | (2.51 | ) | $ | 0.41 | $ | (1.06 | ) | |||||
Refining margin adjusted for FIFO impact(4) | $ | 7.48 | $ | 9.56 | $ | 9.51 | $ | 8.44 | |||||||
Direct operating expenses and major scheduled turnaround expenses(1)(2) | $ | 4.44 | $ | 4.56 | $ | 4.86 | $ | 5.73 | |||||||
Direct operating expenses and major scheduled turnaround expenses per barrel sold(1)(7) | $ | 4.12 | $ | 4.33 | $ | 4.54 | $ | 5.34 | |||||||
Barrels sold (barrels per day)(7) | 230,345 | 213,368 | 229,439 | 207,669 | |||||||||||
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Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||||||||||
% | % | % | % | ||||||||||||||||||||
Refining Throughput and Production Data (bpd) | |||||||||||||||||||||||
Throughput: | |||||||||||||||||||||||
Sweet | 202,070 | 91.0 | 176,674 | 83.9 | 199,973 | 88.8 | 173,700 | 85.5 | |||||||||||||||
Medium | — | — | 3,429 | 1.6 | — | — | 2,471 | 1.2 | |||||||||||||||
Heavy sour | 11,771 | 5.3 | 22,433 | 10.7 | 14,130 | 6.3 | 17,174 | 8.5 | |||||||||||||||
Total crude oil throughput | 213,841 | 96.3 | 202,536 | 96.2 | 214,103 | 95.1 | 193,345 | 95.2 | |||||||||||||||
All other feedstocks and blendstocks | 8,113 | 3.7 | 7,952 | 3.8 | 11,161 | 4.9 | 9,827 | 4.8 | |||||||||||||||
Total throughput | 221,954 | 100.0 | 210,488 | 100.0 | 225,264 | 100.0 | 203,172 | 100.0 | |||||||||||||||
Production: | |||||||||||||||||||||||
Gasoline | 112,284 | 50.4 | 108,330 | 51.3 | 115,600 | 51.2 | 107,105 | 52.7 | |||||||||||||||
Distillate | 96,578 | 43.4 | 86,622 | 41.0 | 93,260 | 41.3 | 82,309 | 40.5 | |||||||||||||||
Other (excluding internally produced fuel) | 13,775 | 6.2 | 16,280 | 7.7 | 17,019 | 7.5 | 13,900 | 6.8 | |||||||||||||||
Total refining production (excluding internally produced fuel) | 222,637 | 100.0 | 211,232 | 100.0 | 225,879 | 100.0 | 203,314 | 100.0 | |||||||||||||||
Product price (dollars per gallon): | |||||||||||||||||||||||
Gasoline | $ | 1.52 | $ | 1.44 | $ | 1.53 | $ | 1.24 | |||||||||||||||
Distillate | 1.51 | 1.37 | 1.54 | 1.22 | |||||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Market Indicators (dollars per barrel) | |||||||||||||||
West Texas Intermediate (WTI) NYMEX | $ | 48.15 | $ | 45.64 | $ | 49.95 | $ | 39.78 | |||||||
Crude Oil Differentials: | |||||||||||||||
WTI less WTS (light/medium sour) | 1.06 | 0.83 | 1.24 | 0.49 | |||||||||||
WTI less WCS (heavy sour) | 10.00 | 12.92 | 11.88 | 13.26 | |||||||||||
NYMEX Crack Spreads: | |||||||||||||||
Gasoline | 18.07 | 19.13 | 16.39 | 17.53 | |||||||||||
Heating Oil | 15.11 | 12.82 | 15.32 | 12.37 | |||||||||||
NYMEX 2-1-1 Crack Spread | 16.59 | 15.98 | 15.85 | 14.95 | |||||||||||
PADD II Group 3 Basis: | |||||||||||||||
Gasoline | (3.95 | ) | (5.49 | ) | (2.96 | ) | (5.68 | ) | |||||||
Ultra Low Sulfur Diesel | (0.62 | ) | (1.18 | ) | (1.10 | ) | (1.10 | ) | |||||||
PADD II Group 3 Product Crack Spread: | |||||||||||||||
Gasoline | 14.12 | 13.64 | 13.42 | 11.85 | |||||||||||
Ultra Low Sulfur Diesel | 14.49 | 11.63 | 14.23 | 11.27 | |||||||||||
PADD II Group 3 2-1-1 | 14.30 | 12.64 | 13.82 | 11.56 | |||||||||||
(1) | Amounts are shown exclusive of depreciation and amortization. |
(2) | Direct operating expense is presented on a per crude oil throughput barrel basis. In order to derive the direct operating expenses per crude oil throughput barrel, we utilize the total direct operating expenses, which do not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period. |
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(3) | Gross profit, a U.S. generally accepted accounting principles ("GAAP") measure, is calculated as the difference between net sales and cost of materials and other, direct operating expenses (exclusive of depreciation and amortization), major scheduled turnaround expenses, and depreciation and amortization. Each of the components used in this calculation are taken directly from our Condensed Consolidated Statements of Operations. In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period. |
(4) | Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of materials and other. Refining margin is a non-GAAP measure that management believes is important to investors in evaluating the performance of our refineries as a general indication of the amount above our cost of materials and other at which we are able to sell refined products. Each of the components used in this calculation (net sales and cost of materials and other) are taken directly from our Condensed Consolidated Statements of Operations. Our calculation of refining margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin and refining margin per crude oil throughput barrel are important to enable investors to better understand and evaluate our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance. |
Refining margin per crude oil throughput barrel adjusted for FIFO impact is a measurement calculated as the difference between net sales and cost of materials and other adjusted for FIFO impact. Refining margin adjusted for FIFO impact is a non-GAAP measure that we believe is important to investors in evaluating our refineries’ performance as a general indication of the amount above our cost of materials and other (taking into account the impact of our utilization of FIFO) at which we are able to sell refined products. Our calculation of refining margin adjusted for FIFO impact may differ from calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. Under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO impact when crude oil prices increase and an unfavorable FIFO impact when crude oil prices decrease. In order to derive the refining margin per crude oil throughput barrel adjusted for FIFO impact, we utilize the total dollar figures for refining margin adjusted for FIFO impact as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin adjusted for FIFO impact and refining margin per crude oil throughput barrel adjusted for FIFO impact are important to enable investors to better understand and evaluate our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance.
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The calculation of refining margin, refining margin adjusted for FIFO impact, refining margin per crude oil throughput barrel and refining margin adjusted for FIFO impact per crude oil throughput barrel (each a non-GAAP financial measure), including a reconciliation to the most directly comparable GAAP financial measure for the three and six months ended June 30, 2017 and 2016 is as follows:
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions) | |||||||||||||||
Net sales | $ | 1,338.2 | $ | 1,164.4 | $ | 2,761.7 | $ | 1,998.4 | |||||||
Cost of materials and other | 1,208.0 | 941.9 | 2,409.3 | 1,664.2 | |||||||||||
Direct operating expenses (exclusive of depreciation and amortization and major scheduled turnaround expenses as reflected below) | 83.5 | 81.9 | 172.7 | 170.2 | |||||||||||
Major scheduled turnaround expenses | 2.8 | 2.1 | 15.7 | 31.5 | |||||||||||
Depreciation and amortization | 31.7 | 30.9 | 65.0 | 61.8 | |||||||||||
Gross profit (loss) | 12.2 | 107.6 | 99.0 | 70.7 | |||||||||||
Add: | |||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization and major scheduled turnaround expenses as reflected below) | 83.5 | 81.9 | 172.7 | 170.2 | |||||||||||
Major scheduled turnaround expenses | 2.8 | 2.1 | 15.7 | 31.5 | |||||||||||
Depreciation and amortization | 31.7 | 30.9 | 65.0 | 61.8 | |||||||||||
Refining margin | 130.2 | 222.5 | 352.4 | 334.2 | |||||||||||
FIFO impact, (favorable) unfavorable | 15.4 | (46.2 | ) | 15.7 | (37.4 | ) | |||||||||
Refining margin adjusted for FIFO impact | $ | 145.6 | $ | 176.3 | $ | 368.1 | $ | 296.8 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||
Total crude oil throughput barrels per day | 213,841 | 202,536 | 214,103 | 193,345 | |||||||
Days in the period | 91 | 91 | 181 | 182 | |||||||
Total crude oil throughput barrels | 19,459,531 | 18,430,776 | 38,752,643 | 35,188,790 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions, except for $ per barrel data) | |||||||||||||||
Refining margin | $ | 130.2 | $ | 222.5 | $ | 352.4 | $ | 334.2 | |||||||
Divided by: crude oil throughput barrels | 19.5 | 18.4 | 38.8 | 35.2 | |||||||||||
Refining margin per crude oil throughput barrel | $ | 6.69 | $ | 12.07 | $ | 9.10 | $ | 9.50 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions, except for $ per barrel data) | |||||||||||||||
Refining margin adjusted for FIFO impact | $ | 145.6 | $ | 176.3 | $ | 368.1 | $ | 296.8 | |||||||
Divided by: crude oil throughput barrels | 19.5 | 18.4 | 38.8 | 35.2 | |||||||||||
Refining margin adjusted for FIFO impact per crude oil throughput barrel | $ | 7.48 | $ | 9.56 | $ | 9.51 | $ | 8.44 | |||||||
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(5) | EBITDA and Adjusted EBITDA. EBITDA represents net income (loss) before (i) interest expense and other financing costs, net of interest income, (ii) income tax expense and (iii) depreciation and amortization. Adjusted EBITDA represents EBITDA adjusted for (i) FIFO impact (favorable) unfavorable, (ii) major scheduled turnaround expenses (that many of our competitors capitalize and thereby exclude from their measures of EBITDA and adjusted EBITDA), (iii) (gain) loss on derivatives, net and (iv) current period settlements on derivative contracts. We present Adjusted EBITDA because it is the starting point for our determination of available cash for distribution. EBITDA and Adjusted EBITDA are not recognized terms under GAAP and should not be substituted for net income (loss) or cash flow from operations. Management believes that EBITDA and Adjusted EBITDA enable investors to better understand our ability to make distributions to our common unitholders, help investors evaluate our ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance. EBITDA and Adjusted EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently. Below is a reconciliation of net income (loss) to EBITDA and EBITDA to Adjusted EBITDA for the three and six months ended June 30, 2017 and 2016: |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions) | |||||||||||||||
Net income (loss) | $ | (19.2 | ) | $ | 78.1 | $ | 47.8 | $ | 10.1 | ||||||
Add: | |||||||||||||||
Interest expense and other financing costs, net of interest income | 11.8 | 10.1 | 23.0 | 20.9 | |||||||||||
Income tax expense | — | — | — | — | |||||||||||
Depreciation and amortization | 32.4 | 31.6 | 66.5 | 63.1 | |||||||||||
EBITDA | 25.0 | 119.8 | 137.3 | 94.1 | |||||||||||
Add: | |||||||||||||||
FIFO impact, (favorable) unfavorable(a) | 15.4 | (46.2 | ) | 15.7 | (37.4 | ) | |||||||||
Major scheduled turnaround expenses(b) | 2.8 | 2.1 | 15.7 | 31.5 | |||||||||||
(Gain) loss on derivatives, net | — | 1.9 | (12.2 | ) | 3.1 | ||||||||||
Current period settlements on derivative contracts(c) | (0.1 | ) | 7.1 | 1.1 | 28.5 | ||||||||||
Adjusted EBITDA | $ | 43.1 | $ | 84.7 | $ | 157.6 | $ | 119.8 | |||||||
(a) | FIFO is our basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO impact when crude oil prices increase and an unfavorable FIFO impact when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. In order to derive the FIFO impact per crude oil throughput barrel, we utilize the total dollar figures for the FIFO impact and divide by the number of crude oil throughput barrels for the period. |
(b) | Represents expense associated with major scheduled turnaround activities at the Wynnewood refinery and the Coffeyville refinery during 2017 and 2016, respectively. |
(c) | Represents the portion of (gain) loss on derivatives, net related to contracts that matured during the respective periods and settled with counterparties. There are no premiums paid or received at the inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts. |
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(6) | Available cash for distribution is generally equal to Adjusted EBITDA reduced for cash needed for (i) debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for major scheduled turnaround expenses and, to the extent applicable, (iv) reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any. Available cash for distribution may be increased by the release of previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of our general partner. Available cash for distribution is not a recognized term under GAAP. Available cash for distribution should not be considered in isolation or as an alternative to net income (loss) or operating income (loss), as a measure of operating performance. In addition, available cash for distribution is not presented as, and should not be considered an alternative to cash flows from operations or as a measure of liquidity. Available cash for distribution as reported by the Partnership may not be comparable to similarly titled measures of other entities, thereby limiting its usefulness as a comparative measure. |
Three Months Ended June 30, 2017 | Six Months Ended June 30, 2017 | ||||||
(in millions, except per unit data) | |||||||
Reconciliation of Adjusted EBITDA to Available cash for distribution | |||||||
Adjusted EBITDA | $ | 43.1 | $ | 157.6 | |||
Adjustments: | |||||||
Less: | |||||||
Cash needs for debt service | (10.0 | ) | (20.0 | ) | |||
Reserves for environmental and maintenance capital expenditures | (18.1 | ) | (53.1 | ) | |||
Reserves for major scheduled turnaround expenses | (15.0 | ) | (30.0 | ) | |||
Reserves for future operating needs | — | (54.5 | ) | ||||
Available cash for distribution | $ | — | $ | — | |||
Available cash for distribution, per unit | $ | — | $ | — | |||
Common units outstanding | 147.6 | 147.6 | |||||
(7) | Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refineries. We utilize total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of barrels sold for the period to derive the metric. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions) | |||||||||||||||
Coffeyville Refinery Financial Results | |||||||||||||||
Net sales | $ | 859.8 | $ | 778.0 | $ | 1,811.1 | $ | 1,306.0 | |||||||
Cost of materials and other | 773.5 | 630.7 | 1,581.9 | 1,093.4 | |||||||||||
Direct operating expenses (exclusive of depreciation and amortization and major scheduled turnaround expenses as reflected below) | 47.5 | 46.1 | 98.2 | 93.8 | |||||||||||
Major scheduled turnaround expenses | — | 2.1 | — | 31.5 | |||||||||||
Depreciation and amortization | 17.4 | 16.7 | 36.4 | 33.5 | |||||||||||
Gross profit | $ | 21.4 | $ | 82.4 | $ | 94.6 | $ | 53.8 | |||||||
Plus: | |||||||||||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization as reflected below) | 47.5 | 48.2 | 98.2 | 125.3 | |||||||||||
Depreciation and amortization | 17.4 | 16.7 | 36.4 | 33.5 | |||||||||||
Refining margin | 86.3 | 147.3 | 229.2 | 212.6 | |||||||||||
FIFO impact, (favorable) unfavorable | 10.1 | (30.2 | ) | 11.6 | (26.4 | ) | |||||||||
Refining margin adjusted for FIFO impact | $ | 96.4 | $ | 117.1 | $ | 240.8 | $ | 186.2 | |||||||
37
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(dollars per barrel) | |||||||||||||||
Coffeyville Refinery Key Operating Statistics | |||||||||||||||
Per crude oil throughput barrel: | |||||||||||||||
Gross profit | $ | 1.76 | $ | 7.11 | $ | 3.95 | $ | 2.53 | |||||||
Refining margin(1) | $ | 7.09 | $ | 12.71 | $ | 9.57 | $ | 9.99 | |||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | $ | 3.90 | $ | 4.16 | $ | 4.10 | $ | 5.89 | |||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold | $ | 3.61 | $ | 3.84 | $ | 3.74 | $ | 5.28 | |||||||
Barrels sold (barrels per day) | 144,479 | 138,021 | 145,014 | 130,429 | |||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||||||
% | % | % | % | ||||||||||||||||
Coffeyville Refinery Throughput and Production Data (bpd) | |||||||||||||||||||
Throughput: | |||||||||||||||||||
Sweet | 122,048 | 87.3 | 101,548 | 76.2 | 118,167 | 84.0 | 97,242 | 78.1 | |||||||||||
Medium | — | — | 3,429 | 2.6 | — | — | 2,471 | 2.0 | |||||||||||
Heavy sour | 11,771 | 8.4 | 22,433 | 16.8 | 14,130 | 10.0 | 17,174 | 13.8 | |||||||||||
Total crude oil throughput | 133,819 | 95.7 | 127,410 | 95.6 | 132,297 | 94.0 | 116,887 | 93.9 | |||||||||||
All other feedstocks and blendstocks | 6,077 | 4.3 | 5,844 | 4.4 | 8,482 | 6.0 | 7,594 | 6.1 | |||||||||||
Total throughput | 139,896 | 100.0 | 133,254 | 100.0 | 140,779 | 100.0 | 124,481 | 100.0 | |||||||||||
Production: | |||||||||||||||||||
Gasoline | 70,032 | 49.3 | 67,819 | 49.9 | 72,271 | 50.5 | 65,927 | 52.2 | |||||||||||
Distillate | 59,703 | 42.1 | 57,549 | 42.4 | 59,573 | 41.6 | 52,348 | 41.4 | |||||||||||
Other (excluding internally produced fuel) | 12,146 | 8.6 | 10,491 | 7.7 | 11,246 | 7.9 | 8,130 | 6.4 | |||||||||||
Total refining production (excluding internally produced fuel) | 141,881 | 100.0 | 135,859 | 100.0 | 143,090 | 100.0 | 126,405 | 100.0 | |||||||||||
(1) The calculation of refining margin and refining margin adjusted for FIFO impact per crude oil throughput barrel for the three and six month ended June 30, 2017 and 2016 is as follows:
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||
Total crude oil throughput barrels per day | 133,819 | 127,410 | 132,297 | 116,887 | |||||||
Days in the period | 91 | 91 | 181 | 182 | |||||||
Total crude oil throughput barrels | 12,177,529 | 11,594,310 | 23,945,757 | 21,273,434 | |||||||
38
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions, except for $ per barrel data) | |||||||||||||||
Refining margin | $ | 86.3 | $ | 147.3 | $ | 229.2 | $ | 212.6 | |||||||
Divided by: crude oil throughput barrels | 12.2 | 11.6 | 23.9 | 21.3 | |||||||||||
Refining margin per crude oil throughput barrel | $ | 7.09 | $ | 12.71 | $ | 9.57 | $ | 9.99 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions, except for $ per barrel data) | |||||||||||||||
Refining margin adjusted for FIFO impact | $ | 96.4 | $ | 117.1 | $ | 240.8 | $ | 186.2 | |||||||
Divided by: crude oil throughput barrels | 12.2 | 11.6 | 23.9 | 21.3 | |||||||||||
Refining margin adjusted for FIFO impact per crude oil throughput barrel | $ | 7.92 | $ | 10.09 | $ | 10.06 | $ | 8.75 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions) | |||||||||||||||
Wynnewood Refinery Financial Results | |||||||||||||||
Net sales | $ | 477.3 | $ | 385.3 | $ | 948.4 | $ | 690.1 | |||||||
Cost of materials and other | 434.6 | 311.3 | 827.7 | 570.7 | |||||||||||
Direct operating expenses (exclusive of depreciation and amortization and major scheduled turnaround expenses as reflected below) | 36.0 | 35.8 | 74.6 | 76.4 | |||||||||||
Major scheduled turnaround expenses | 2.8 | — | 15.7 | — | |||||||||||
Depreciation and amortization | 12.8 | 12.6 | 25.6 | 25.2 | |||||||||||
Gross profit (loss) | $ | (8.9 | ) | $ | 25.6 | $ | 4.8 | $ | 17.8 | ||||||
Plus: | |||||||||||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization as reflected below) | 38.8 | 35.8 | 90.3 | 76.4 | |||||||||||
Depreciation and amortization | 12.8 | 12.6 | 25.6 | 25.2 | |||||||||||
Refining margin | 42.7 | 74.0 | 120.7 | 119.4 | |||||||||||
FIFO impact, (favorable) unfavorable | 5.2 | (15.9 | ) | 4.1 | (11.0 | ) | |||||||||
Refining margin adjusted for FIFO impact | $ | 47.9 | $ | 58.1 | $ | 124.8 | $ | 108.4 | |||||||
39
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(dollars per barrel) | |||||||||||||||
Wynnewood Refinery Key Operating Statistics | |||||||||||||||
Per crude oil throughput barrel: | |||||||||||||||
Gross profit (loss) | $ | (1.23 | ) | $ | 3.74 | $ | 0.33 | $ | 1.27 | ||||||
Refining margin(1) | $ | 5.87 | $ | 10.83 | $ | 8.15 | $ | 8.58 | |||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | $ | 5.33 | $ | 5.24 | $ | 6.10 | $ | 5.49 | |||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold | $ | 4.97 | $ | 5.22 | $ | 5.91 | $ | 5.44 | |||||||
Barrels sold (barrels per day) | 85,866 | 75,347 | 84,425 | 77,239 | |||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||||||
% | % | % | % | ||||||||||||||||
Wynnewood Refinery Throughput and Production Data (bpd) | |||||||||||||||||||
Throughput: | |||||||||||||||||||
Sweet | 80,022 | 97.5 | 75,126 | 97.3 | 81,806 | 96.8 | 76,458 | 97.2 | |||||||||||
Medium | — | — | — | — | — | — | — | — | |||||||||||
Heavy sour | — | — | — | — | — | — | — | — | |||||||||||
Total crude oil throughput | 80,022 | 97.5 | 75,126 | 97.3 | 81,806 | 96.8 | 76,458 | 97.2 | |||||||||||
All other feedstocks and blendstocks | 2,036 | 2.5 | 2,108 | 2.7 | 2,679 | 3.2 | 2,233 | 2.8 | |||||||||||
Total throughput | 82,058 | 100.0 | 77,234 | 100.0 | 84,485 | 100.0 | 78,691 | 100.0 | |||||||||||
Production: | |||||||||||||||||||
Gasoline | 42,252 | 52.3 | 40,511 | 53.7 | 43,329 | 52.3 | 41,178 | 53.5 | |||||||||||
Distillate | 36,875 | 45.7 | 29,073 | 38.6 | 33,687 | 40.7 | 29,961 | 39.0 | |||||||||||
Other (excluding internally produced fuel) | 1,629 | 2.0 | 5,789 | 7.7 | 5,773 | 7.0 | 5,770 | 7.5 | |||||||||||
Total refining production (excluding internally produced fuel) | 80,756 | 100.0 | 75,373 | 100.0 | 82,789 | 100.0 | 76,909 | 100.0 | |||||||||||
(1) The calculation of refining margin and refining margin adjusted for FIFO impact per crude oil throughput barrel for the three and six month ended June 30, 2017 and 2016 is as follows:
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||
Total crude oil throughput barrels per day | 80,022 | 75,126 | 81,806 | 76,458 | |||||||
Days in the period | 91 | 91 | 181 | 182 | |||||||
Total crude oil throughput barrels | 7,282,002 | 6,836,466 | 14,806,886 | 13,915,356 | |||||||
40
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions, except for $ per barrel data) | |||||||||||||||
Refining margin | $ | 42.7 | $ | 74.0 | $ | 120.7 | $ | 119.4 | |||||||
Divided by: crude oil throughput barrels | 7.3 | 6.8 | 14.8 | 13.9 | |||||||||||
Refining margin per crude oil throughput barrel | $ | 5.87 | $ | 10.83 | $ | 8.15 | $ | 8.58 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(in millions, except for $ per barrel data) | |||||||||||||||
Refining margin adjusted for FIFO impact | $ | 47.9 | $ | 58.1 | $ | 124.8 | $ | 108.4 | |||||||
Divided by: crude oil throughput barrels | 7.3 | 6.8 | 14.8 | 13.9 | |||||||||||
Refining margin adjusted for FIFO impact per crude oil throughput barrel | $ | 6.59 | $ | 8.51 | $ | 8.43 | $ | 7.79 | |||||||
41
Three Months Ended June 30, 2017 Compared to the Three Months Ended June 30, 2016
Net Sales. Net sales were $1,338.2 million for the three months ended June 30, 2017 compared to $1,164.4 million for the three months ended June 30, 2016. The increase of $173.8 million, or 15%, was largely the result of higher sales prices for our transportation fuels and by-products, as well as an increase in sales volumes. For the three months ended June 30, 2017, our average sales price per gallon for gasoline of $1.52 increased by approximately 5.6%, as compared to $1.44 for the three months ended June 30, 2016, and our average sales price per gallon for distillates of $1.51 for the three months ended June 30, 2017 increased by approximately 10.2%, as compared to $1.37 for the three months ended June 30, 2016. Overall sales volumes increased approximately 5.4% for the three months ended June 30, 2017, as compared to the three months ended June 30, 2016. Sales volumes for the three months ended June 30, 2016 were impacted by slightly decreased production as a result of a minor crude unit outage at the Wynnewood refinery during the second quarter of 2016.
The following table demonstrates the impact of changes in sales volumes and sales prices for gasoline and distillates for the three months ended June 30, 2017 compared to the three months ended June 30, 2016:
Three Months Ended June 30, 2017 | Three Months Ended June 30, 2016 | Total Variance | ||||||||||||||||||||||||||||||||||
Volume(1) | $ per barrel | Sales $(2) | Volume(1) | $ per barrel | Sales $(2) | Volume(1) | Sales $(2) | Price Variance | Volume Variance | |||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||
Gasoline | 10.8 | $ | 63.77 | $ | 689.1 | 10.5 | $ | 60.67 | $ | 636.7 | 0.3 | $ | 52.4 | $ | 33.4 | $ | 19.0 | |||||||||||||||||||
Distillate | 9.1 | $ | 63.24 | $ | 579.9 | 8.3 | $ | 57.62 | $ | 481.1 | 0.8 | $ | 98.8 | $ | 51.5 | $ | 47.3 | |||||||||||||||||||
(1) Barrels in millions
(2) Sales dollars in millions
Cost of materials and other. Cost of materials and other includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, RINs and transportation and distribution costs. Cost of materials and other was $1,208.0 million for the three months ended June 30, 2017 compared to $941.9 million for the three months ended June 30, 2016. The increase of $266.1 million, or 28.2%, was primarily the result of increases in the cost of consumed crude oil and an increase in RINs expense. The increase in consumed crude oil costs was due to a combined increase in crude oil throughput volume and prices. The WTI benchmark crude price increased approximately 5.5% from the three months ended June 30, 2016. Our average cost per barrel of crude oil consumed for the three months ended June 30, 2017 was $48.19 compared to $42.47 for the comparable period of 2016, an increase of approximately 13.5%. Our crude oil throughput volume increased by approximately 5.6% for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016. RINs expense for the three months ended June 30, 2017 was approximately $105.6 million, a significant increase of $54.6 million, or 107.0% as compared to $51.0 million for the three months ended June 30, 2016. The increase in RINs expense for the three months ended June 30, 2017 was primarily due to the increased market value of the uncommitted obligation. RINs expense includes the impact of recognizing the Partnership’s uncommitted biofuel blending obligation at fair value based on market prices at each reporting date. Under the FIFO method of accounting, changes in crude oil prices can also cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable or unfavorable FIFO inventory impact when crude oil prices increase or decrease. For the three months ended June 30, 2017, we had an unfavorable FIFO inventory impact of $15.4 million compared to a favorable FIFO inventory impact of $46.2 million for the comparable period of 2016.
Refining margin per barrel of crude oil throughput decreased to $6.69 for the three months ended June 30, 2017 from $12.07 for the three months ended June 30, 2016. Refining margin adjusted for FIFO impact was $7.48 per crude oil throughput barrel for the three months ended June 30, 2017, as compared to $9.56 per crude oil throughput barrel for the three months ended June 30, 2016. Gross profit per barrel decreased to $0.63 for the three months ended June 30, 2017, as compared to gross profit per barrel of $5.84 in the equivalent period in 2016. The decrease in refining margin and gross profit per barrel was primarily due to an increase in consumed crude oil costs, and an increase in RINs expense. These costs increases were partially offset by an increase in the sales prices of gasoline and distillates as a result of a slight increase in the spread between transportation fuels and crude oil pricing and favorable changes in the gasoline basis and the distillate basis. The NYMEX 2-1-1 crack spread for the three months ended June 30, 2017 was $16.59 per barrel, an increase of approximately 3.8% over the NYMEX 2-1-1 crack spread of $15.98 per barrel for the three months ended June 30, 2016. The Group 3 gasoline basis was ($3.95) per barrel for the three months ended June 30, 2017 as compared to ($5.49) per barrel for the three months ended June 30, 2016. The Group 3 distillate basis was ($0.62) per barrel for the three months ended June 30, 2017 as compared to ($1.18) per barrel for the three months ended June 30, 2016.
42
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) include costs associated with the actual operations of our refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) were $86.3 million for the three months ended June 30, 2017 compared to direct operating expenses and major scheduled turnaround expenses of $84.0 million for the three months ended June 30, 2016. The increase of $2.3 million was primarily the result of an increase in energy and utility costs ($3.5 million) and an increase in outside services ($1.6 million). These increases were partially offset by a decrease in labor costs ($1.7 million) and a decrease in production chemicals ($1.1 million). Direct operating expenses per barrel of crude oil throughput for the three months ended June 30, 2017 decreased to $4.44 per barrel, as compared to $4.56 per barrel for the three months ended June 30, 2016. The decrease in the direct operating expenses per barrel of crude oil throughput is primarily a function of higher throughput rates.
Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Selling, general and administrative expenses include the direct selling, general and administrative expenses of our business, as well as certain expenses incurred on our behalf by CVR Energy and CRLLC and billed or allocated to us. Selling, general and administrative expenses (exclusive of depreciation and amortization) were $18.9 million for the three months ended June 30, 2017 compared to $16.8 million for the three months ended June 30, 2016. The increase of approximately $2.1 million was primarily due to an increase in share-based compensation expense due to an increase in the market value of the Partnership's common units.
Operating Income (Loss). Operating loss was ($7.4) million for the three months ended June 30, 2017, as compared to operating income of $90.1 million for the three months ended June 30, 2016. The decrease of $97.5 million was primarily the result of a decrease in the refining margin of $92.3 million due to higher crude oil consumption costs and RINs expense, an increase in direct operating expenses of $2.3 million and an increase in selling, general and administrative expenses of $2.1 million.
Interest Expense. Interest expense for the three months ended June 30, 2017 was $12.0 million, as compared to $10.1 million for the three months ended June 30, 2016. The increase of $1.9 million was the result of higher capitalized interest during 2016, primarily related to the hydrogen plant project at the Coffeyville refinery, partially offset by no interest on the intercompany credit facility during 2017.
Loss on Derivatives, net. For the three months ended June 30, 2017, we recorded no net loss or gain on derivatives. This compares to a $1.9 million net loss on derivatives for the three months ended June 30, 2016. This change was primarily due to a significant decrease in the volume of derivatives positions during 2017 and changes in crack spreads during the periods. We enter into commodity hedging instruments in order to fix the price on a portion of our future crude oil purchases and to fix the margin on a portion of future production.
43
Six Months Ended June 30, 2017 Compared to the Six Months Ended June 30, 2016
Net Sales. Net sales were $2,761.7 million for the six months ended June 30, 2017 compared to $1,998.4 million for the six months ended June 30, 2016. The increase of $763.3 million was largely the result of higher sales prices for our transportation fuels and by-products, as well as increased sales volumes. For the six months ended June 30, 2017, our average sales price per gallon for gasoline of $1.53, increased by approximately 23.4%, as compared to $1.24 for the six months ended June 30, 2016, and our average sales price per gallon for distillates of $1.54 for the six months ended June 30, 2017, increased by approximately 26.2%, as compared to $1.22 for the six months ended June 30, 2016. Overall sales volumes increased approximately 9.1% for the six months ended June 30, 2017, as compared to the six months ended June 30, 2016. Sales volumes for the six months ended June 30, 2016 were impacted by decreased production as a result of the second phase of the major scheduled turnaround completed at the Coffeyville refinery during the first quarter of 2016.
The following table demonstrates the impact of changes in sales volumes and sales prices for gasoline and distillates for the six months ended June 30, 2017 compared to the six months ended June 30, 2016.
Six Months Ended June 30, 2017 | Six Months Ended June 30, 2016 | Total Variance | ||||||||||||||||||||||||||||||||||
Volume(1) | $ per barrel | Sales $(2) | Volume(1) | $ per barrel | Sales $(2) | Volume(1) | Sales $(2) | Price Variance | Volume Variance | |||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||
Gasoline | 23.1 | $ | 64.21 | $ | 1,480.2 | 21.3 | $ | 52.02 | $ | 1,106.7 | 1.8 | $ | 373.5 | $ | 280.9 | $ | 92.6 | |||||||||||||||||||
Distillate | 17.4 | $ | 64.69 | $ | 1,124.1 | 15.7 | $ | 51.27 | $ | 805.3 | 1.7 | $ | 318.8 | $ | 233.2 | $ | 85.6 | |||||||||||||||||||
(1) Barrels in millions
(2) Sales dollars in millions
Cost of materials and other. Cost of materials and other includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, RINs and transportation and distribution costs. Cost of materials and other was $2,409.3 million for the six months ended June 30, 2017 compared to $1,664.2 million for the six months ended June 30, 2016. The increase of $745.1 million, or 44.8%, was primarily the result of increases in the cost of consumed crude oil and other feedstock and increase in costs of products purchased for resale. The increase in consumed crude oil costs was due to a combined increase in crude oil throughput volume and crude prices. The WTI benchmark crude price increased approximately 25.6% from the six months ended June 30, 2016. Our average cost per barrel of crude oil consumed for the six months ended June 30, 2017 was $49.64 compared to $37.35 for the comparable period of 2016, an increase of approximately 32.9%. Our crude oil throughput volume increased by approximately 10.7% for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016 due primarily to the completion of the second phase of the major scheduled turnaround at the Coffeyville refinery in the first quarter of 2016. The increase in the cost of other feedstocks was primarily due to an increase in purchase prices for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016. Under the FIFO method of accounting, changes in crude oil prices can also cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable or unfavorable FIFO inventory impact when crude oil prices increase or decrease. For the six months ended June 30, 2017, we had an unfavorable FIFO inventory impact of $15.7 million compared to a favorable FIFO inventory impact of $37.4 million for the comparable period of 2016.
Refining margin per barrel of crude oil throughput decreased to $9.10 for the six months ended June 30, 2017 from $9.50 for the six months ended June 30, 2016. Refining margin adjusted for FIFO impact was $9.51 per crude oil throughput barrel for the six months ended June 30, 2017, as compared to $8.44 per crude oil throughput barrel for the six months ended June 30, 2016. Gross profit per barrel increased to $2.56 per barrel for the six months ended June 30, 2017, as compared to $2.01 per barrel in the comparative period in 2016. The decrease in refining margin per barrel was primarily due to an increase in consumed crude oil costs and the cost of products purchased for resale. The increase in gross profit per barrel was primarily due to a higher spread between crude oil and transportation fuels pricing, a favorable change in gasoline basis and lower major scheduled turnaround expenses. The NYMEX 2-1-1 crack spread for the six months ended June 30, 2017 was $15.85 per barrel, an increase of approximately 6.0% over the NYMEX 2-1-1 crack spread of $14.95 per barrel for the six months ended June 30, 2016. The Group 3 gasoline basis was ($2.96) per barrel for the six months ended June 30, 2017 as compared to $(5.68) per barrel for the six months ended June 30, 2016.
44
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) include costs associated with the actual operations of our refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) were $188.4 million for the six months ended June 30, 2017 compared to $201.7 million for the six months ended June 30, 2016. The decrease of $13.3 million was the result of a decrease in turnaround expenses in 2017 compared to 2016 ($15.8 million), a decrease in labor costs ($3.9 million) and a decrease in production chemicals ($3.0 million). These decreases were partially offset by an increase in energy and utility costs ($9.1 million). Direct operating expenses per barrel of crude oil throughput for the six months ended June 30, 2017 decreased to $4.86 per barrel, as compared to $5.73 per barrel for the six months ended June 30, 2016. The decrease in the direct operating expenses per barrel of crude oil throughput is primarily a function of lower overall expenses and higher throughput rates.
Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Selling, general and administrative expenses include the direct selling, general and administrative expenses of our business, as well as certain expenses incurred on our behalf by CVR Energy and CRLLC and billed or allocated to us. Selling, general and administrative expenses (exclusive of depreciation and amortization) were $38.9 million for the six months ended June 30, 2017 compared to $35.3 million for the six months ended June 30, 2016. The increase of approximately $3.6 million was primarily due to an increase in share-based compensation expense.
Operating Income. Operating income was $58.6 million for the six months ended June 30, 2017, as compared to operating income of $34.1 million for the six months ended June 30, 2016. The increase of $24.5 million was primarily the result of an increase in refining margin of $18.2 million due to higher sales prices for our transportation fuels and by-products, and a decrease in direct operating expenses of $13.3 million as a result of a decrease in turnaround expense in 2017 compared to 2016.
Interest Expense. Interest expense for the six months ended June 30, 2017 was $23.2 million, as compared to $20.9 million for the six months ended June 30, 2016. The increase of approximately $2.3 million was the result of higher capitalized interest during 2016, primarily related to the hydrogen plant project at the Coffeyville refinery, partially offset by no interest on the intercompany credit facility during 2017.
Gain (loss) on Derivatives, net. For the six months ended June 30, 2017, we recorded a $12.2 million net gain on derivatives. This compares to a $3.1 million net loss on derivatives for the six months ended June 30, 2016. This change was primarily due to a significant decrease in the volume of derivatives positions and settlement of open positions during 2017 and changes in crack spreads during the periods. We enter into commodity hedging instruments in order to fix the price on a portion of our future crude oil purchases and to fix the margin on a portion of future production.
45
Liquidity and Capital Resources
Our principal uses of cash are for working capital, capital expenditures, funding our debt service obligations and paying distributions to our unitholders, as discussed further below.
We believe that our cash flows from operations and existing cash and cash equivalents, along with borrowings, as necessary, under the Amended and Restated ABL Credit Facility (or any replacement facility) and the $250.0 million intercompany credit facility, will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next 12 months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors, including using cash to satisfy our unfulfilled RIN obligation. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control.
Our general partner's current policy is to distribute an amount equal to the available cash we generate each quarter to our unitholders. As a result, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance our growth externally, the growth in our business, and our liquidity, may be negatively impacted.
Cash Balance and Other Liquidity
As of June 30, 2017, we had cash and cash equivalents of $515.7 million. Working capital at June 30, 2017 was $380.4 million, consisting of $938.6 million in current assets and $558.2 million in current liabilities. Working capital at December 31, 2016 was $313.7 million, consisting of $803.6 million in current assets and $489.9 million in current liabilities. As of July 25, 2017, we had cash and cash equivalents of $547.0 million.
The Amended and Restated ABL Credit Facility provides us with borrowing availability of up to $400.0 million with an incremental facility, subject to compliance with a borrowing base. The Amended and Restated ABL Credit Facility is scheduled to mature on December 20, 2017. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Partnership and the credit facility provides for loans and letters of credit in an amount up to the aggregate availability under the facility, subject to meeting certain borrowing base conditions, with sub-limits of 10% of the total facility commitment for swing line loans and 90% of the total facility commitment for letters of credit. The intercompany credit facility provides us with borrowing availability of up to $250.0 million.
As of June 30, 2017, we had $333.2 million available under the Amended and Restated ABL Credit Facility and $250.0 million available under the intercompany credit facility. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions.
We are considering various refinancing options in association with the Amended and Restated ABL Credit Facility maturity. We believe that our cash from operations and available borrowings under our intercompany credit facility, together with the options management is considering, will be adequate to satisfy anticipated commitments and planned capital expenditures for the next 12 months.
Borrowing Activities
2022 Notes. On October 23, 2012, Refining LLC and Coffeyville Finance issued $500.0 million aggregate principal amount of the 2022 Notes. The debt issuance cost of the 2022 Notes totaled approximately $8.7 million and is being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. As of June 30, 2017, the 2022 Notes had an aggregate principal balance and a net carrying value of $500.0 million.
The 2022 Notes are fully and unconditionally guaranteed by CVR Refining and each of Refining LLC's existing domestic subsidiaries (other than the co-issuer, Coffeyville Finance) on a joint and several basis. After January 23, 2013, the 2022 Notes were no longer secured.
The 2022 Notes bear interest at a rate of 6.5% per annum and mature on November 1, 2022, unless earlier redeemed or repurchased. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, to holders of record at the close of business on April 15 and October 15, as the case may be, immediately preceding each such interest payment date.
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We have the right to redeem the 2022 Notes at a redemption price of (i) 103.250% of the principal amount thereof, if redeemed during the 12 month period beginning on November 1, 2017; (ii) 102.167% of the principal amount thereof, if redeemed during the 12 month period beginning on November 1, 2018; (iii) 101.083% of the principal amount thereof, if redeemed during the 12 month period beginning on November 1, 2019 and (iv) 100% of the principal amount, if redeemed on or after November 1, 2020, in each case, plus any accrued and unpaid interest. Prior to November 1, 2017, some or all of the 2022 Notes may be redeemed at a price equal to 100% of the principal amount thereof, plus a make-whole premium and any accrued and unpaid interest.
In the event of a "change of control," the issuers are required to offer to buy back all of the 2022 Notes at 101% of their principal amount. A change of control is generally defined as (i) the direct or indirect sale or transfer (other than by a merger) of all or substantially all of the assets of Refining LLC to any person other than qualifying owners (as defined in the indenture), (ii) liquidation or dissolution of Refining LLC, or (iii) any person, other than a qualifying owner, directly or indirectly acquiring 50% of the membership interest of Refining LLC.
The indenture governing the 2022 Notes imposes covenants that restrict the ability of the credit parties to (i) issue debt, (ii) incur or otherwise cause liens to exist on any of their property or assets, (iii) declare or pay dividends, repurchase equity, or make payments on contractually subordinated debt, (iv) make certain investments, (v) sell certain assets, (vi) merge, consolidate with or into another entity, or sell all or substantially all of their assets, and (vii) enter into certain transactions with affiliates. Most of the foregoing covenants would cease to apply at such time that the 2022 Notes are rated investment grade by both Standard & Poor's Ratings Services and Moody's Investors Service, Inc. However, such covenants would be re-instituted if the 2022 Notes subsequently lost their investment grade rating. In addition, the indenture contains customary events of default, the occurrence of which would result in, or permit the trustee or the holders of at least 25% of the 2022 Notes to cause, the acceleration of the 2022 Notes, in addition to the pursuit of other available remedies.
The indenture governing the 2022 Notes prohibits us from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, the indenture limits our ability to pay distributions to unitholders. The covenants will apply differently depending on our fixed charge coverage ratio (as defined in the indenture). If the fixed charge coverage ratio is not less than 2.5 to 1.0, we will generally be permitted to make restricted payments, including distributions to our unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, we will generally be permitted to make restricted payments, including distributions to our unitholders, up to an aggregate $100.0 million basket plus certain other amounts referred to as "incremental funds" under the indenture. We were in compliance with the covenants as of June 30, 2017, and the ratio was satisfied (not less than 2.5 to 1.0).
Amended and Restated Asset Based (ABL) Credit Facility.
On December 20, 2012, we entered into the Amended and Restated ABL Credit Facility with Wells Fargo Bank, National Association as administrative agent and collateral agent for a syndicate of lenders. The Amended and Restated ABL Credit Facility replaced CRLLC's prior ABL credit facility. Under the Amended and Restated ABL Credit Facility, we assumed CRLLC's position as borrower and its obligations under the Amended and Restated ABL Credit Facility upon the closing of the initial public offering on January 23, 2013. The Amended and Restated ABL Credit Facility is a $400.0 million asset-based revolving credit facility, with sub-limits for letters of credit and swing line loans of $360.0 million and $40.0 million, respectively. The Amended and Restated ABL Credit Facility also includes a $200.0 million uncommitted incremental facility. The Amended and Restated ABL Credit Facility permits the payment of distributions, subject to the following conditions: (i) no default or event of default exists, (ii) excess availability and projected excess availability at all times during the three-month period following the distribution exceeds 20% of the lesser of the borrowing base and the total commitments; provided, that, if excess availability and projected excess availability for the six-month period following the distribution is greater than 25% at all times, then the following condition in clause (iii) will not apply, and (iii) the fixed charge coverage ratio for the immediately preceding twelve-month period shall be equal to or greater than 1.10 to 1.00. The Amended and Restated ABL Credit Facility has a five-year maturity and may be used for working capital and other general corporate purposes (including permitted acquisitions).
Borrowings under the Amended and Restated ABL Credit Facility bear interest at either a base rate or LIBOR plus an applicable margin. The applicable margin is (i) (a) 1.75% for LIBOR borrowings and (b) 0.75% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% of the lesser of the borrowing base and the total commitments and (ii) (a) 2.00% for LIBOR borrowings and (b) 1.00% for prime rate borrowings, in each case if quarterly average excess availability is less than or equal to 50% of the lesser of the borrowing base and the total commitments. The Amended and Restated ABL Credit Facility also requires the payment of customary fees, including an unused line fee of (i) 0.40% if the daily average amount of loans and letters of credit outstanding is less than 50% of the lesser of the borrowing base and the total
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commitments and (ii) 0.30% if the daily average amount of loans and letters of credit outstanding is equal to or greater than 50% of the lesser of the borrowing base and the total commitments. We are also required to pay customary letter of credit fees equal to, for standby letters of credit, the applicable margin on LIBOR loans on the maximum amount available to be drawn under and, for commercial letters of credit, the applicable margin on LIBOR loans less 0.50% on the maximum amount available to be drawn under, and customary facing fees equal to 0.125% of the face amount of, each letter of credit.
The lenders under the Amended and Restated ABL Credit Facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in the ABL Priority Collateral (as defined in the ABL Intercreditor Agreement) and a second priority lien (subject to certain customary exceptions) and security interest in the Note Priority Collateral (as defined in the ABL Intercreditor Agreement).
The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Credit Parties and their subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investments and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The amended and restated facility also contains a fixed charge coverage ratio financial covenant, as defined under the facility. We were in compliance with the covenants of the Amended and Restated ABL Credit Facility as of June 30, 2017.
Intercompany Credit Facility. The Partnership maintains a $250.0 million intercompany credit facility with CRLLC as the lender to be used to fund growth capital expenditures. The intercompany credit facility has a term of six years and bears interest at a rate of LIBOR plus 3% per annum.
The intercompany credit facility contains covenants that require us to, among other things, notify CRLLC of the occurrence of any default or event of default and provide CRLLC with information in respect of our business and financial status as it may reasonably require, including, but not limited to, copies of our unaudited quarterly financial statements and our audited annual financial statements. We were in compliance with the covenants of the intercompany credit facility as of June 30, 2017.
In addition, the intercompany credit facility contains customary events of default, including, among others, failure to pay any sum payable when due; the occurrence of a default under other indebtedness in excess of $25.0 million; and the occurrence of an event that results in either (i) CRLLC no longer directly or indirectly controlling our general partner, or (ii) CRLLC and its affiliates no longer owning a majority of our equity interests. During the fourth quarter of 2016, we repaid outstanding borrowings of $31.5 million under the intercompany credit facility. As of June 30, 2017, we had no borrowings outstanding and $250.0 million available under the intercompany credit facility.
Capital Spending
We divide our capital spending needs into two categories: maintenance and growth. Maintenance capital spending includes only non-discretionary maintenance projects and projects required to comply with environmental, health and safety regulations. We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields and/or a reduction in direct operating expenses. Major scheduled turnaround expenses are expensed when incurred.
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The following table summarizes our total actual capital expenditures for the six months ended June 30, 2017 and current estimated capital expenditures for the full year 2017 by major category. These estimates may change as a result of unforeseen circumstances or a change in our plans, and amounts may not be spent in the manner allocated below:
Six Months Ended June 30, 2017 | 2017 Estimate | ||||||
Actual | |||||||
(in millions) | |||||||
Coffeyville refinery: | |||||||
Maintenance | $ | 25.0 | $ | 60.0 | |||
Growth | 3.7 | 15.0 | |||||
Coffeyville refinery total capital spending | 28.7 | 75.0 | |||||
Wynnewood refinery: | |||||||
Maintenance | 15.6 | 55.0 | |||||
Growth | 0.8 | 5.0 | |||||
Wynnewood refinery total capital spending | 16.4 | 60.0 | |||||
Other: | |||||||
Maintenance | 2.3 | 15.0 | |||||
Growth | — | — | |||||
Other total capital spending | 2.3 | 15.0 | |||||
Total capital spending | $ | 47.4 | $ | 150.0 | |||
Our estimated capital expenditures are subject to change due to unanticipated increases/decreases in the cost, scope and completion time for our capital projects. For example, we may experience increases/decreases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of our refineries. We may also accelerate or defer some capital expenditures from time to time.
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Cash Flows
The following table sets forth our consolidated cash flows for the periods indicated below:
Six Months Ended June 30, | |||||||
2017 | 2016 | ||||||
(unaudited) | |||||||
(in millions) | |||||||
Net cash provided by (used in): | |||||||
Operating activities | $ | 251.3 | $ | 40.8 | |||
Investing activities | (48.8 | ) | (68.0 | ) | |||
Financing activities | (0.9 | ) | (0.8 | ) | |||
Net increase (decrease) in cash and cash equivalents | $ | 201.6 | $ | (28.0 | ) | ||
Cash Flows Provided by Operating Activities
For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital.
Net cash flows provided by operating activities for the six months ended June 30, 2017 were approximately $251.3 million. The positive cash flow from operating activities generated over this period was primarily driven by net income of $47.8 million, favorable changes to other working capital of $107.3 million, non-cash depreciation and amortization of $66.5 million and cash inflow of $34.4 million for trade working capital, partially offset by net derivatives activity of $11.1 million. The cash inflow from other working capital was primarily due to a decrease in prepaid expense ($21.1 million) and an increase in accrued expenses and other current liabilities ($86.2 million). The increase in other current liabilities was primarily due to an increased biofuel blending obligation as a result of the increased market value of RINs as applied to the uncommitted required volumes at June 30, 2017, partially offset by an decrease in accrued interest due to timing of semi-annual payments on the 2022 Senior Notes. The net cash inflow for trade working capital was attributable to decreases in accounts receivable of $9.5 million and inventory of $34.8 million, partially offset by a decrease in accounts payable of $9.9 million. The decreases in accounts receivable and inventory were primarily due to reductions in gasoline, distillates and crude oil pricing.
Net cash flows provided by operating activities for the six months ended June 30, 2016 were approximately $40.8 million. The positive cash flow from operating activities generated over this period was primarily driven by realized gains on derivatives of $28.5 million, favorable changes to other working capital of $24.5 million and non-cash depreciation and amortization of $63.1 million and net income of $10.1 million, offset by cash outflows of $93.2 million for trade working capital. The net cash outflow for trade working capital was attributable to increases in accounts receivable of $45.3 million and inventories of $19.3 million and a decrease in accounts payable of $28.6 million. The increase in accounts receivable was primarily due to increased pricing for both gasoline and distillates. The increase in inventories was also primarily attributable to increased pricing for both gasoline and distillates, as well as higher crude oil pricing. The decrease in accounts payable was primarily attributable to the payables associated with the turnaround at our Coffeyville refinery which was completed during the first quarter of 2016. Other working capital changes primarily related to increases in accrued expenses and other current liabilities of $30.4 million, which was primarily due to an increase in our biofuel blending obligation under the RFS, partially offset by a reduction in personnel accruals.
Cash Flows Used In Investing Activities
Net cash used in investing activities for the six months ended June 30, 2017 was $48.8 million compared to $68.0 million for the six months ended June 30, 2016. The decrease in cash used in investing activities was primarily due to a decrease in capital expenditures of $20.6 million, primarily associated with the completion of the hydrogen plant in 2016, partially offset by a $1.4 million contribution to an equity method investment.
Cash Flows Used in Financing Activities
Net cash used in financing activities was $0.9 million and $0.8 million, respectively, for the six months ended June 30, 2017 and 2016. The net cash used in financing activities for the six months ended June 30, 2017 and 2016 was attributable to capital lease payments.
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As of and for the six months ended June 30, 2017, there were no borrowings or repayments under the Amended and Restated ABL Credit Facility or under the intercompany credit facility.
Contractual Obligations
As of June 30, 2017, our contractual obligations included long-term debt, operating leases, capital lease obligations, unconditional purchase obligations, environmental liabilities and interest payments. There were no material changes outside the ordinary course of our business with respect to our contractual obligations during the six months ended June 30, 2017 from those disclosed in our 2016 Form 10-K.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of June 30, 2017, as defined within the rules and regulations of the SEC.
Recent Accounting Pronouncements
Refer to Part I, Item 1, Note 3 ("Recent Accounting Pronouncements") of this Report for a discussion of recent accounting pronouncements applicable to the Partnership.
Critical Accounting Policies
Our critical accounting policies are disclosed in the "Critical Accounting Policies" section of our 2016 Form 10-K. No modifications have been made to our critical accounting policies.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices, RINs prices and interest rates. Except as discussed below, information about market risks for the six months ended June 30, 2017 does not differ materially from that discussed under Part II — Item 7A of our 2016 Form 10-K. We are exposed to market pricing for all of the products sold in the future, as all our products are commodities.
Our earnings and cash flows and estimates of future cash flows are sensitive to changes in energy prices. The prices of crude oil and refined products have fluctuated substantially in recent years. These prices depend on many factors, including the overall demand for crude oil and refined products, which in turn depends, among other factors, on general economic conditions, the level of foreign and domestic production of crude oil and refined products, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels, the extent of government regulations and global market dynamics. The prices we receive for refined products are also affected by factors such as local market conditions and the level of operations of other refineries in our markets. The prices at which we can sell gasoline and other refined products are strongly influenced by the price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. The timing of the relative movement of the prices, however, can impact profit margins, which could significantly affect our earnings and cash flows.
Commodity Price Risk
At June 30, 2017, the Partnership had no open commodity swap instruments.
Compliance Program Price Risk
As a producer of transportation fuels from petroleum, we are required to blend biofuels into the products we produce or to purchase RINs in the open market in lieu of blending to meet the mandates established by the EPA. We are exposed to market risk related to the volatility in the price of RINs needed to comply with the RFS. To mitigate the impact of this risk on our results of operations and cash flows, we purchase RINs when prices are deemed favorable or otherwise appropriate for business purposes. See Note 11 ("Commitments and Contingencies") to Part I, Item 1 of this Report and “Major Influences on Results of Operations” in Part I, Item 2 of this Report for further discussion about compliance with the RFS.
Foreign Currency Exchange
Given that our operations are based entirely in the United States, we are not significantly exposed to foreign currency exchange rate risk. A portion of our pipeline transportation costs are transacted in Canadian dollars. Commitments for future periods under this agreement reflect the exchange rate between the Canadian Dollar and the U.S. Dollar as of the end of the reporting period. Based on the short period of time between the billing and settlement of these transportation costs in Canadian dollars, the exposure to foreign currency exchange rate risk and the resulting foreign currency gain (loss) is not considered material.
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Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of June 30, 2017, we have evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. It should be noted that any system of disclosure controls and procedures, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the system are met. In addition, the design of any system of disclosure controls and procedures is based in part upon assumptions about the likelihood of future events. Due to these and other inherent limitations of any such system, there can be no assurance that any design will always succeed in achieving its stated goals under all potential future conditions.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting required by Rule 13a-15 of the Exchange Act that occurred during the fiscal quarter ended June 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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Part II. Other Information
Item 1. Legal Proceedings
See Note 11 ("Commitments and Contingencies") to Part I, Item 1 of this Report, which is incorporated by reference into this Part II, Item 1, for a description of certain litigation, legal and administrative proceedings and environmental matters.
Item 1A. Risk Factors
There have been no material changes from the risk factors previously disclosed in the "Risk Factors" section of our 2016 Form 10-K.
Item 6. Exhibits
See the accompanying Exhibit Index and related note following the signature page to this Report for a list of exhibits filed or furnished with this Report, which Exhibit Index and note are incorporated herein by reference.
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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.
CVR Refining, LP | |||
By: | CVR Refining GP, LLC, its general partner | ||
July 28, 2017 | By: | /s/ JOHN J. LIPINSKI | |
Chief Executive Officer and President | |||
(Principal Executive Officer) | |||
July 28, 2017 | By: | /s/ SUSAN M. BALL | |
Chief Financial Officer and Treasurer | |||
(Principal Financial and Accounting Officer) | |||
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EXHIBIT INDEX | ||
Exhibit Number | Exhibit Title | |
31.1* | Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer and President. | |
31.2* | Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer and Treasurer. | |
32.1† | Section 1350 Certification of Chief Executive Officer and President. | |
32.2† | Section 1350 Certification of Chief Financial Officer and Treasurer. | |
101* | The following financial information for CVR Refining, LP's Quarterly Report on Form 10-Q for the quarter ended June 30, 2017 formatted in XBRL ("Extensible Business Reporting Language") includes: (i) Condensed Consolidated Balance Sheets (unaudited), (ii) Condensed Consolidated Statements of Operations (unaudited), (iii) Condensed Consolidated Statement of Changes in Partners' Capital (unaudited), (iv) Condensed Consolidated Statements of Cash Flows (unaudited), and (v) the Notes to Condensed Consolidated Financial Statements (unaudited), tagged in detail. | |
* | Filed herewith. |
† | Furnished herewith. |
PLEASE NOTE: Pursuant to the rules and regulations of the SEC, we may file or incorporate by reference agreements as exhibits to the reports which we file with or furnish to the SEC. The agreements are filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Partnership or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in the Partnership's public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about the Partnership or its business or operations on the date hereof.
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