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 Annual Report on Form 10-K for the year ended December 31, 2014 filed with the Securities and Exchange Commission ("SEC") as of February 20, 2015 (the "2014 Form 10-K"). Results of operations and cash flows for the three months ended March 31, 2015 are not necessarily indicative of results to be attained for any other period.
This Report, including this Management's Discussion and Analysis of Financial Condition and Results of Operations, contains "forward-looking statements" as defined by the 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 in the summary risks noted below:
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 gasoline and diesel RINs, as well as environmental and other governmental permits necessary for the operation of our business;
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changes in laws, regulations and policies with respect to the export of crude oil or other hydrocarbons;
costs of compliance with existing or 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;
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 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.
We are an independent downstream energy limited partnership with refining and related logistics assets that operates in the underserved 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 oil (within its rated capacity of 70,000 bpcd). In addition, our supporting businesses include (1) a crude oil gathering system with a gathering capacity of over 60,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri and Texas, (2) a 170,000 bpd pipeline system (supported by approximately 336 miles of owned and leased pipelines) that transports crude oil to our Coffeyville refinery from our Broome Station facility located near Caney, Kansas, (3) over 6.0 million barrels of owned and leased crude oil storage, (4) 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 (5) approximately 4.5 million barrels of combined refinery related 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, Enterprise and NuStar.
Crude oil is supplied to our Coffeyville refinery through our gathering system and by a pipeline owned by Plains that runs from Cushing to our Broome Station facility. We maintain capacity on the Keystone and Spearhead pipelines from Canada to Cushing. We will also maintain contracted capacity on the Pony Express pipeline by the second quarter of 2015 and the White Cliffs pipeline by the end of 2015 with both pipelines originating in Colorado and extending to Cushing. We also maintain leased and owned storage in Cushing to facilitate optimal crude oil purchasing and blending. Our Coffeyville refinery blend consists of a combination of crude oil grades, including domestic grades and various Canadian medium and heavy sours. Crude oil is supplied to our Wynnewood refinery through three third-party pipelines operated by Sunoco Pipeline, Excel Pipeline and Blueknight Pipeline and historically has mainly been sourced from Texas and Oklahoma. Our Wynnewood refinery is capable of processing a variety of crudes, including WTS, WTI, sweet and sour Canadian and other U.S. domestically produced crude oils. In the fourth quarter of 2014, we completed a hydrocracker project that increased the conversion capability and the ULSD yield of the Wynnewood refinery. The access to a variety of crude oils coupled with the complexity of our refineries allows us to purchase crude oil at a discount to WTI. Our consumed crude oil cost discount to WTI for the first quarter of 2015 was $1.10 per barrel compared to $2.68 per barrel in the first quarter of 2014.
Second Underwritten Offering
On June 30, 2014, we completed a second underwritten offering (the "Second Underwritten Offering") by selling 6,500,000 common units to the public at a price of $26.07 per unit. We utilized net proceeds of approximately $164.1 million from the Second Underwritten Offering to redeem 6,500,000 common units from CVR Refining Holdings, LLC ("CVR Refining Holdings"). Subsequent to the closing of the Second Underwritten Offering and through July 23, 2014, public security holders held approximately 33% of all outstanding limited partner interests, and CVR Refining Holdings held approximately 67% of all outstanding limited partner interests.
On July 24, 2014, we sold an additional 589,100 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their option to purchase additional common units. We utilized net proceeds of approximately $14.9 million from the underwriters' exercise of their option to purchase additional common units to redeem an equal amount of common units from CVR Refining Holdings. Additionally, on July 24, 2014, CVR Refining Holdings sold 385,900 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of $9.7 million.
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Subsequent to the closing of the underwriters' option of the Second Underwritten Offering and as of March 31, 2015, public security holders held approximately 34% of all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 4% of all outstanding limited partner interests), and CVR Refining Holdings held approximately 66% of all outstanding limited partner interests in addition to owning 100% of our general partner.
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, 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 home heating oil during the winter, primarily in the Northeast. 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 Renewable Fuel Standard ("RFS") of the United States Environmental Protection Agency (the "EPA"), which requires us to either blend "renewable fuels" in with our transportation fuels or purchase renewable fuel credits, known as renewable identification numbers ("RINs"), in lieu of blending.
The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the forthcoming year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending. In 2013, the Wynnewood refinery was subject to the RFS for the first time.
During 2013, the cost of RINs was extremely volatile as the EPA's proposed renewable fuel volume mandates approached the "blend wall." The blend wall refers to the point at which refiners are required to blend more ethanol into the transportation fuel supply than can be supported by the demand for gasoline containing more than 10% ethanol by volume ("E10 gasoline"). In November 2013, the EPA published the proposed annual renewable fuel percentage standards for 2014, which acknowledged the blend wall and were generally lower than the volumes for 2013 and lower than statutory mandates. The price of RINs decreased significantly after the 2014 proposed percentage standards were published; however, RIN prices remained volatile and increased subsequently in 2014. During 2014, the EPA extended the compliance demonstration deadline for the 2013 RFS to 30 days following the publication of the final 2014 annual renewable fuel percentage standards. On April 20, 2015, the Federal Register published notice of a proposed settlement between the EPA and several industry organizations regarding the deadlines for issuing the percentage standards for 2014 and 2015 under the RFS program. If finalized, the EPA will (i) propose 2015 percentage standards by June 1, 2015, (ii) resolve a pending petition to waive statutorily mandated volume requirements for 2014 by November 30, 2015 and (iii) finalize 2014 and 2015 percentage standards by November 30, 2015. The EPA also separately announced it will propose the RFS percentage standards for 2016 by June 1, 2015 and issue final standards by November 30, 2015.
The cost of RINs for the three months ended March 31, 2015 and 2014 was approximately $36.6 million and $34.7 million, respectively. The future cost of RINs for our business is difficult to estimate, particularly until such time that the 2014 renewable fuel percentage standards are finalized and the 2015 renewable fuel percentage standards are announced. 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, all of which can vary significantly from quarter to quarter. Based upon recent market prices
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of RINs and current estimates related to the other variable factors, we estimate that the total cost of RINs will be approximately $125.0 million to $175.0 million for the year ending December 31, 2015.
If sufficient RINs are unavailable for purchase at times when we seek to purchase RINs, or if we have to pay a significantly higher price for RINs or if we are subject to penalties as a result of delays in our ability to timely deliver RINs to the EPA, our business, financial condition and results of operations could be materially adversely affected. Many petroleum refiners blend renewable fuel into their transportation fuels and do not have to pass on the costs of compliance through the purchase of RINs to their customers. Therefore, it may be significantly harder for us to pass on the costs of compliance with RFS to our customers.
In order to assess our operating performance, we compare our net sales, less cost of product sold (exclusive of depreciation and amortization), 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 is 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 refinery 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 refinery 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 refinery margin can be impacted significantly by the consumed crude oil differential. Our consumed crude oil differential will move directionally with changes in the WTS price differential to WTI and the WCS price differential to WTI as both these differentials indicate 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 light medium sour crude oil and heavy sour crude oil we purchase as a percent of our total crude oil volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate.
We produce a high volume of high value products, such as gasoline and distillates. We benefit from the fact that our marketing region consumes more refined products than it produces, resulting in prices that reflect the logistics cost for Gulf Coast refineries to ship into our region. The result of this logistical advantage and 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 that 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.
We are significantly affected by developments in the markets in which we operate. For example, numerous pipeline projects in 2014 and 2015 expanded the connectivity of the Cushing and Permian Basin markets to the gulf coast, resulting in a decrease in the domestic crude advantage. Additionally, in late 2014, market factors resulted in a rapid downward price adjustment in the oil and gas industry. The resultant spike in volatility continuing in 2015 has caused major adjustments in oil debt markets as well as announced and expected cuts in 2015 budgets in both North American shale and Canadian projects. The refining industry is directly impacted by these events and could see a downward movement in refining margins as a result.
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 three months ended March 31, 2015, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $3.3 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 petroleum product inventory position relative to other refiners. This target inventory position is generally not hedged. To the extent our inventory position deviates from the target level, we consider risk mitigation activities usually through the purchase or sale of futures contracts on the NYMEX. Our hedging activities carry customary time, location and product grade basis risks
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generally associated with hedging activities. Because most of our titled inventory is valued under the FIFO costing method, price fluctuations on our target level of titled inventory have a major effect on our financial results.
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. Our Coffeyville refinery completed the first phase of a two-phase turnaround during the fourth quarter of 2011. The second phase was completed during the first quarter of 2012 and the first phase of its next turnaround is scheduled to begin in late 2015, with the second phase scheduled to begin in early 2016. We completed a turnaround at our Wynnewood refinery in December 2012, and the next turnaround is scheduled to occur in the spring of 2017.
Agreements with Affiliates
In connection with the initial public offering of CVR Energy and the transfer of the nitrogen fertilizer business to CVR Partners in October 2007, CVR Energy and its subsidiaries entered into a number of 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 CVR Partners' initial public offering, CVR Energy, directly or through its subsidiaries, amended and restated certain of the intercompany agreements and entered into several new agreements with CVR Partners. In connection with our Initial Public Offering, 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 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; and (vi) 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 . . .
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