Exhibit 99.2
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our consolidated financial statements and notes included elsewhere in this Form 8-K (and related exhibits). We refer to the assets, liabilities and operations of DCP Southeast Texas Holdings, GP, or Southeast Texas, prior to our 66.67% acquisition from DCP Midstream, LLC in March 2012, DCP SC Texas GP, or the Eagle Ford system, prior to our 33.33% and 46.67% acquisitions from DCP Midstream, LLC in November 2012 and March 2013, respectively, and the Lucerne 1 plant, prior to our acquisition from DCP Midstream, LLC in March 2014, as our "predecessor".
Overview
We are a Delaware limited partnership formed by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. Our operations are organized into three business segments: Natural Gas Services, NGL Logistics and Wholesale Propane Logistics.
Our business is impacted by commodity prices, which we significantly mitigate on an overall Partnership basis through a multi-year hedging program, volumes of throughput and sales of natural gas, NGLs and condensate. Various factors impact both commodity prices and volumes. Commodity prices historically have been volatile and continue to be volatile. Crude oil prices have generally remained at favorable levels, while NGL and natural gas prices remain modest due to increasing supplies. The twelve-month average New York Mercantile Exchange, or NYMEX, price of natural gas futures contracts per MMBtu was $4.19, $3.54, and $3.24 as of December 31, 2013, 2012 and 2011, respectively. The twelve-month average price per gallon for NGLs was $0.84, $1.08 and $1.39 as of December 31, 2013, 2012 and 2011, respectively, and the price of crude oil per barrel was $98.04, $94.16 and $95.12 as of December 31, 2013, 2012 and 2011, respectively.
Although we have not experienced a significant impact to our natural gas throughput volumes as a result of decreased commodity prices, if commodity prices remain weak for a sustained period, our natural gas throughput volumes may be impacted, particularly if producers were to shut in gas. Natural gas drilling activity levels vary by geographic area, but in general, drilling remains firm in areas with liquids rich gas. Drilling remains weak in certain areas with dry gas where relatively lower commodity prices currently do not support the economics of drilling. However, advances in technology, such as horizontal drilling and hydraulic fracturing in shale plays, have led to certain geographic areas becoming increasingly accessible. Our long-term view is that commodity prices will be at levels that we believe will support sustained or increasing levels of domestic natural gas production. We use direct NGL hedges to mitigate a significant portion of our NGL price exposure; however, weakening of the relationship of natural gas liquids to crude oil prices does modestly impact the effectiveness of our hedging program to mitigate our exposure to price fluctuations where we use crude oil to hedge our NGL price exposure.
Our fee-based business which represents a significant portion of our estimated margins, plus our highly hedged commodity position, mitigated a significant portion of our natural gas, NGL, and condensate commodity price risk.
NGL prices are also impacted by the demand from petrochemical and refining industries. The petrochemical industry is making significant investment in building or expanding facilities to convert chemical plants from heavier oil-based feed stock to lighter NGL-based feed stock, including ethane. This increased demand should support increasing ethane supplies. In addition, propane export facilities are being expanded or built, which is supporting increasing propane supply. Although there can be, and has been, near-term volatility in NGL prices, longer term we believe there will be sufficient demand in NGLs to support increasing supply.
The global economic outlook continues to be cause for concern for U.S. financial markets and businesses and investors alike. This uncertainty may contribute to volatility in financial and commodity markets.
The amount of NGLs we produce, fractionate, transport, sell and store, may be reduced if the pipelines and storage and fractionation facilities to which we deliver NGLs are capacity constrained and cannot, or will not, accept the NGLs. Recent capacity expansions are coming online, which we believe will mitigate the risk of these NGL capacity constraints.
Increased activity levels in liquids rich gas basins combined with access to capital markets at relatively low historical costs have enabled us to continue executing our multi-faceted growth strategy, with an emphasis on dropdowns from DCP Midstream, LLC. Our multi-faceted growth strategy may take numerous forms such as dropdown opportunities from DCP Midstream, LLC, joint venture opportunities, organic build opportunities within our footprint and third-party acquisitions. Dropdowns from DCP Midstream, LLC in 2013 totaled over $1 billion. In 2014, we will continue executing our multi-faceted growth strategy, with an emphasis on dropdowns from DCP Midstream, LLC and organic growth.
Some of our recent growth projects include the following:
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| • | On February 25, 2014, we entered into various transaction documents with DCP Midstream, LLC and its affiliates for the contribution or acquisition of (i) the remaining 20% interest in DCP SC Texas GP; (ii) a 33.33% membership interest in each DCP Southern Hills Pipeline, LLC, which owns the Southern Hills pipeline, and DCP Sand Hills Pipeline, LLC, which owns the Sand Hills pipeline; (iii) a 35 MMcf/d cryogenic natural gas processing plant located in Weld County, Colorado, or the Lucerne 1 plant; and (iv) a 200 MMcf/d cryogenic natural gas processing plant also located in Weld County, Colorado, which is currently under construction, or the Lucerne 2 plant. Total consideration for these transactions at closing was $1,220 million, subject to certain working capital and other customary adjustments. These transactions closed in March 2014. |
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| • | On August 5, 2013, we entered into a purchase and sale agreement with a 100% owned subsidiary of DCP Midstream, LLC pursuant to which the Partnership acquired all of the membership interests in DCP LaSalle Plant LLC, or the LaSalle Transaction, for consideration of $209 million, subject to certain customary purchase price adjustments. DCP LaSalle Plant LLC owns the O'Connor plant, a cryogenic natural gas processing plant with initial capacity of 110 MMcf/d, previously known as the LaSalle plant, in the DJ Basin in Weld County, Colorado. In connection with the LaSalle Transaction, we also entered into a 15-year fee-based processing agreement with an affiliate of DCP Midstream, LLC pursuant to which such affiliate agreed to pay us (i) a fixed demand charge of 75% of the plant's capacity, and (ii) a throughput fee on all volumes processed for such affiliate at the O'Connor plant. The processing agreement commenced with commercial operations of the new plant in October 2013. As of February 2014, the O'Connor plant expansion to 160 MMcf/d is mechanically complete. |
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| • | On August 5, 2013, we entered into a purchase and sale agreement with a 100% owned subsidiary of DCP Midstream, LLC pursuant to which the Partnership acquired all of the membership interests in DCP Midstream Front Range LLC, or Front Range, for consideration of $86 million, subject to certain customary purchase price adjustments. Front Range owns a 33.33% equity interest in Front Range Pipeline LLC, a joint venture with affiliates of Enterprise and Anadarko Petroleum Corporation, which was formed to construct the Front Range pipeline, a new raw NGL mix pipeline that originates in the DJ Basin and extends approximately 435 miles to Skellytown, Texas. Enterprise is the operator of the pipeline, which was placed into service in February 2014. |
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| • | On March 28, 2013, we acquired an additional 46.67% interest in the Eagle Ford system from DCP Midstream, LLC and fixed price commodity derivative hedges for a three-year period for aggregate consideration of $626 million. We have an 80% interest in the construction of the Goliad 200 MMcf/d natural gas processing plant, including fixed price commodity price hedges, representing a total investment of approximately $290 million, which was placed into service in February 2014. |
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| • | The construction of the Texas Express pipeline, of which we own a 10% interest, is complete and commenced operations in the fourth quarter of 2013. Originating near Skellytown in Carson County, Texas, the 20-inch diameter Texas Express pipeline extends approximately 580 miles to Enterprise’s natural gas liquids fractionation and storage complex at Mont Belvieu, Texas, and provides access to other third party facilities in the area. |
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| • | Our construction of our 100% owned Eagle 200 MMcf/d natural gas processing plant is complete and commenced operations in the first quarter of 2013. |
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| • | Our expansion plan for Discovery's Keathley Canyon natural gas gathering pipeline system is progressing and is expected to be completed in the fourth quarter of 2014. |
Our capital markets execution has positioned us well in terms of both liquidity and cost of capital to execute our growth plans, including dropdown opportunities with DCP Midstream, LLC. During the year ended December 31, 2013, we received net proceeds of $1,082 million from the issuance of 24,897,977 of our common units and $490 million through a public debt offering of 3.875% 10-year Senior Notes, which were used to finance our growth opportunities. In October 2013, we entered into a Commercial Paper Program pursuant to which we had $335 million outstanding as of December 31, 2013, which is included in short-term borrowings in our consolidated balance sheets. As of December 31, 2013, the unused capacity under the Credit Agreement was $664 million, all of which was available for general working capital purposes, providing liquidity to
continue to execute on our growth plans.
We raised our distribution for the fourth quarter of 2013, resulting in a 6% increase in our quarterly distribution rate over the rate declared for the fourth quarter of 2012. The distribution reflects our business results as well as our recent execution on growth opportunities.
General Trends and Outlook
During 2014, our strategic objectives will continue to focus on maintaining stable distributable cash flows from our existing assets and executing on growth opportunities to increase our long-term distributable cash flows. We believe the key elements to stable distributable cash flows are the diversity of our asset portfolio, our fee-based business which represents a significant portion of our estimated margins, plus our highly hedged commodity position, the objective of which is to protect against downside risk in our distributable cash flows.
We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance capital expenditures of between $35 million and $45 million, and approved expenditures for expansion capital of between $500 million and $600 million, for the year ending December 31, 2014. Expansion capital expenditures include construction of Discovery’s Keathley Canyon Connector, which is shown as investments in unconsolidated affiliates, construction of the Lucerne 2 plant, the Marysville NGL storage project and expansion of our Chesapeake facility, among other projects. The board of directors may, at its discretion, approve additional growth capital during the year.
We expect to continue to pursue a multi-faceted growth strategy, which includes maximizing dropdown opportunities provided by our partnership with DCP Midstream, LLC, capitalizing on organic expansion and opportunities pursuing strategic third party acquisitions in order to grow our distributable cash flows. Given the significant level of growth opportunities currently in DCP Midstream, LLC’s footprint, we would expect substantial emphasis on our dropdown objective over the next few years.
We anticipate our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
Natural Gas Gathering and Processing Margins - Except for our fee-based contracts, which may be impacted by throughput volumes, our natural gas gathering and processing profitability is dependent upon commodity prices, natural gas supply, and demand for natural gas, NGLs and condensate. Commodity prices, which are impacted by the balance between supply and demand, have historically been volatile. Throughput volumes could decline, particularly in areas with lower NGL content, should natural gas prices and drilling levels continue to experience weakness. Our long-term view is that as economic conditions improve, commodity prices should remain at levels that would support continued natural gas production in the United States. During 2013, petrochemical demand remained for NGLs as NGLs were a lower cost feedstock when compared to crude oil derived feedstocks. We anticipate demand for NGLs by the petrochemical industry will continue in 2014.
NGL Logistics - The volumes of NGLs transported on our pipelines, fractionated in our fractionation facilities and stored in our storage facility are dependent on the level of production of NGLs from processing plants connected to our assets. When natural gas prices are high relative to NGL prices, it is less profitable to process natural gas because of the higher value of natural gas compared to the value of NGLs and because of the increased cost of separating the NGLs from the natural gas. As a result, we have experienced periods in the past, in which higher natural gas or lower NGL prices reduce the volume of NGLs extracted at plants connected to our NGL pipelines, fractionation and storage facilities and, in turn, lower the NGL throughput on our assets.
Wholesale Propane Supply and Demand - Due to our multiple propane supply sources, propane supply contractual arrangements, significant storage capabilities, and multiple terminal locations for wholesale propane delivery, we are generally able to provide our propane distribution customers with reliable supplies of propane during peak demand periods of tight supply, usually in the winter months when their customers consume the most propane for heating.
Factors That May Significantly Affect Our Results
Transfers of net assets between entities under common control that represent a change in reporting entity are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method. Accordingly, our consolidated financial statements have been adjusted to include the historical results of our Lucerne 1 plant, our 80% interest in the Eagle Ford system and 100% interest in Southeast Texas for all periods presented, similar to the pooling method. The financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity.
Natural Gas Services Segment
Our results of operations for our Natural Gas Services segment are impacted by (1) increases and decreases in the volume and quality of natural gas that we gather and transport through our systems, which we refer to as throughput, (2) the associated Btu content of our system throughput and our related processing volumes, (3) the prices of and relationship between commodities such as NGLs, crude oil and natural gas, (4) the operating efficiency and reliability of our processing facilities, (5) potential limitations on throughput volumes arising from downstream and infrastructure capacity constraints, (6) the terms of our processing contract arrangements with producers, and (7) increases and decreases in the volume, price and basis differentials of natural gas associated with our natural gas storage and pipeline assets, as well as our underlying derivatives associated with these assets. This is not a complete list of factors that may impact our results of operations but, rather, are those we believe are most likely to impact those results.
Throughput and operating efficiency generally are driven by wellhead production, plant recoveries, operating availability of our facilities, physical integrity and our competitive position on a regional basis, and more broadly by demand for natural gas, NGLs and condensate. Historical and current trends in the price changes of commodities may not be indicative of future trends. Throughput and prices are also driven by demand and take-away capacity for residue natural gas and NGLs.
Our processing contract arrangements can have a significant impact on our profitability and cash flow. Our actual contract terms are based upon a variety of factors, including natural gas quality, geographic location, the commodity pricing environment at the time the contract is executed, customer requirements and competition from other midstream service providers. Our gathering and processing contract mix and, accordingly, our exposure to natural gas, NGL and condensate prices, may change as a result of producer preferences, impacting our expansion in regions where certain types of contracts are more common as well as other market factors.
The capacity on certain downstream NGL and natural gas infrastructure has tightened in recent periods and can be further constrained seasonally or when there is severe weather. Constrained market outlets may restrict us from operating our facilities optimally.
Our Natural Gas Services segment operating results are impacted by market conditions causing variability in natural gas, crude oil and NGL prices. The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs. Although the prevailing price of residue natural gas has less short-term significance to our operating results than the price of NGLs, in the long-term, the growth and sustainability of our business depends on commodity prices being at levels sufficient to provide incentives and capital for producers to explore and produce natural gas.
The prices of NGLs, crude oil and natural gas can be extremely volatile for periods of time, and may not always have a close relationship. Due to our hedging program, changes in the relationship of the price of NGLs and crude oil may cause our commodity price exposure to vary, which we have attempted to capture in our commodity price sensitivities in “Quantitative and Qualitative Disclosures about Market Risk.” Our results may also be impacted as a result of non-cash lower of cost or market inventory or imbalance adjustments, which occur when the market value of commodities decline below our carrying value.
The natural gas services business is highly competitive in our markets and includes major integrated oil and gas companies, interstate and intrastate pipelines, and companies that gather, compress, treat, process, transport, store and/or market natural gas. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices for crude oil, natural gas and/or natural gas liquids. Competition is also increased in those geographic areas where our commercial contracts with our customers are shorter in length of term and therefore must be renegotiated on a more frequent basis.
NGL Logistics Segment
Our NGL Logistics segment operating results are impacted by, among other things, the throughput volumes of the NGLs we transport on our NGL pipelines and the volumes of NGLs we fractionate and store. We transport, fractionate and store NGLs primarily on a fee basis. Throughput may be negatively impacted as a result of our customers operating their processing plants in ethane rejection mode, often as a result of low ethane prices relative to natural gas prices. Factors that impact the supply and demand of NGLs, as described above in our Natural Gas Services segment, may also impact the throughput and volume for our NGL Logistics segment.
Wholesale Propane Logistics Segment
Our Wholesale Propane Logistics segment operating results are impacted by our ability to provide our propane distribution customers with reliable supplies of propane. We use physical inventory, physical purchase agreements and financial derivative instruments, with DCP Midstream, LLC or third parties, which typically match the quantities of propane subject to fixed price sales agreements to mitigate our commodity price risk. Our results may also be impacted as a result of non-cash lower of cost or market inventory adjustments, which occur when the market value of propane declines below our carrying value. We generally recover lower of cost or market inventory adjustments in subsequent periods through the sale of inventory, or settlement of financial derivative instruments. There may be positive or negative impacts on sales volumes and gross margin from supply disruptions and weather conditions in the mid-Atlantic, upper midwestern and northeastern areas of the United States. Our annual sales volumes of propane may decline when these areas experience periods of milder weather in the winter months. Volumes may also be impacted by conservation and reduced demand in a recessionary environment.
The wholesale propane business is highly competitive in our market areas which include the mid-Atlantic, upper midwest and northeastern areas of the United States. Our competitors include major integrated oil and gas and energy companies, interstate and intrastate pipelines, as well as marketers and wholesalers.
Weather
The economic impact of severe weather may negatively affect the nation’s short-term energy supply and demand, and may result in commodity price volatility. Additionally, severe weather may restrict or prevent us from fully utilizing our assets, by damaging our assets, interrupting utilities, and through possible NGL and natural gas curtailments downstream of our facilities, which restricts our production. These impacts may linger past the time of the actual weather event. Severe weather may also impact the supply availability and propane demand in our Wholesale Propane Logistics segment. Although we carry insurance on the vast majority of our assets, insurance may be inadequate to cover our loss in some instances, and in certain circumstances we have been unable to obtain insurance on commercially reasonable terms, if at all. We have recently experienced cold weather and freezing temperatures in certain regions where our assets are located but the effects did not have a material impact on our operations.
Capital Markets
Volatility in the capital markets may impact our business in multiple ways, including limiting our producers’ ability to finance their drilling programs and limiting our ability to fund our operations through dropdowns, organic growth projects and acquistions. These events may impact our counterparties’ ability to perform under their credit or commercial obligations. Where possible, we have obtained additional collateral agreements, letters of credit from highly rated banks, or have managed credit lines to mitigate a portion of these risks.
Impact of Inflation
Inflation has been relatively low in the United States in recent years. However, the inflation rates impacting our business fluctuate throughout the broad economic and energy business cycles. Consequently, our costs for chemicals, utilities, materials and supplies, labor and major equipment purchases may increase during periods of general business inflation or periods of relatively high energy commodity prices.
Other
The above factors, including sustained deterioration in commodity prices and volumes, other market declines or a decline in our unit price, may negatively impact our results of operations, and may increase the likelihood of a non-cash impairment charge or non-cash lower of cost or market inventory adjustments.
Recent Events
On January 28, 2014, we announced that the board of directors of the General Partner declared a quarterly distribution of $0.7325 per unit, payable on February 14, 2014 to unitholders of record on February 7, 2014.
On February 25, 2014, we entered into various transaction documents with DCP Midstream, LLC and its affiliates for the contribution or acquisition of (i) the remaining 20% interest in DCP SC Texas GP; (ii) a 33.33% membership interest in each DCP Southern Hills Pipeline, LLC, which owns the Southern Hills pipeline, and DCP Sand Hills Pipeline, LLC, which owns the Sand Hills pipeline; (iii) a 35 MMcf/d cryogenic natural gas processing plant located in Weld County, Colorado, or the Lucerne 1 plant; and (iv) a 200 MMcf/d cryogenic natural gas processing plant also located in Weld County, Colorado, which is currently under construction, or the Lucerne 2 plant. Total consideration for these transactions at closing was $1,220 million, subject to certain working capital and other customary adjustments. These transactions closed in March 2014. The Southern Hills pipeline is engaged in the business of transporting NGLs, and consists of approximately 800 miles of pipeline, with an expected capacity of 175 MBbls/d after completion of planned pump stations. The pipeline provides NGL takeaway service from the Midcontinent to fractionation facilities along the Texas Gulf Coast and the Mont Belvieu, Texas market hub.The Southern Hills pipeline began taking flows in the first quarter of 2013 and was placed into service in June 2013. The Sand Hills pipeline is also engaged in the business of transporting NGLs and consists of approximately 720 miles of pipeline, with an expected initial capacity of 200 MBbls/d after completion of pump stations, and possible further capacity increases with the installation of additional pump stations. The pipeline provides NGL takeaway service from the Permian and Eagle Ford basins to fractionation facilities along the Texas Gulf Coast and the Mont Belvieu, Texas market hub. The Sand Hills pipeline began taking flows in the fourth quarter of 2012 and was placed into service in June 2013.
Our Operations
We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into our Natural Gas Services segment, our NGL Logistics segment and our Wholesale Propane Logistics segment.
Natural Gas Services Segment
Results of operations from our Natural Gas Services segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, transported, stored and sold through our gathering, processing and pipeline systems; the volumes of NGLs and condensate sold; and the level of our realized natural gas, NGL and condensate prices. We generate our revenues and our gross margin for our Natural Gas Services segment principally from contracts that contain a combination of the following arrangements:
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| • | Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas. Our fee-based arrangements include natural gas arrangements pursuant to which we obtain natural gas at the wellhead or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the transportation fees we would otherwise charge for transportation of natural gas from the wellhead location to the delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced. |
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| • | Percent-of-proceeds/liquids arrangements - Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and condensate based on index prices from published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs and condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between the proceeds received and the amount remitted back to the producer. Under percent-of-liquids arrangements, we do not keep any amounts related to residue natural gas proceeds and only keep amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in the producer retaining title to all or a portion of the residue natural gas and/or the NGLs, in lieu of us returning sales proceeds to the producer. Additionally, these arrangements may include fee-based components. Our revenues under percent-of-proceeds arrangements relate directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly with the price of NGLs and condensate. |
In addition to the above contract types, we have keep-whole arrangements, which are estimated to generate an insignificant portion of our gross margin. Discovery, in which we have a 40% interest, also has keep-whole arrangements. Under the terms of a keep-whole processing contract, natural gas is gathered from the producer for processing, the NGLs and condensate are sold and the residue natural gas is returned to the producer with a Btu content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under this type of contract, we are exposed to the frac spread. The frac spread is the difference between the value of the NGLs and condensate extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL and condensate prices are higher relative to natural gas prices when that frac spread exceeds our operating costs. Fluctuations in commodity prices are expected to continue to impact the operating costs of these entities.
The natural gas supply for our gathering pipelines and processing plants is derived primarily from natural gas wells located in Arkansas, Colorado, Louisiana, Michigan, Oklahoma, Texas, Wyoming and the Gulf of Mexico. We identify primary suppliers as those individually representing 10% or more of our total natural gas supply. We had one supplier of natural gas representing 10% or more of our total natural gas supply during the year ended December 31, 2013. We actively seek new supplies of natural gas, both to offset natural declines in the production from connected wells and to increase throughput volume. We obtain new natural gas supplies in our operating areas by contracting for production from new wells, connecting new wells drilled on dedicated acreage, or by obtaining natural gas that has been directly received or released from other gathering systems.
We sell natural gas to marketing affiliates of natural gas pipelines, integrated oil companies and DCP Midstream, LLC, national wholesale marketers, industrial end-users and gas-fired power plants. We typically sell natural gas under market index related pricing terms. The NGLs extracted from the natural gas at our processing plants are sold at market index prices to DCP Midstream, LLC or its affiliates, or to third parties. In addition, under our merchant arrangements, various DCP Midstream LLC affiliates purchase natural gas from third parties at wellheads, pipeline interconnect and pooling points, as well as residue gas from our Northern Louisiana system, and then resell the aggregated natural gas to third parties.
We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. As a service to our customers, we may enter into physical fixed price natural gas purchases and sales, utilizing financial derivatives to swap this fixed price risk back to market index. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.
A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage.
NGL Logistics Segment
Our pipelines, fractionation facilities and storage facility provide transportation, fractionation and storage services for customers, primarily on a fee basis. We have entered into contractual arrangements with DCP Midstream, LLC and others that generally require customers to pay us to transport or store NGLs pursuant to a fee-based rate that is applied to volumes. Therefore, the results of operations for this business segment are generally dependent upon the volume of product transported, fractionated or stored and the level of fees charged to customers. We do not take title to the products transported on our NGL pipelines, fractionated in our fractionation facilities or stored in our storage facility; rather, the customer retains title and the associated commodity price risk. DCP Midstream, LLC provides 100% of volumes transported on the Wattenberg and Seabreeze pipelines. The volumes of NGLs transported on our pipelines are dependent on the level of production of NGLs from processing plants connected to our NGL pipelines. When natural gas prices are high relative to NGL prices, it is less profitable to process natural gas because of the higher value of natural gas compared to the value of NGLs and because of the increased cost of separating the NGLs from the natural gas. As a result, we have experienced periods in the past, in which higher natural gas or lower NGL prices reduce the volume of NGLs extracted at plants connected to our NGL pipelines and, in turn, lower the NGL throughput on our assets. DCP Midstream, LLC, the largest gatherer and processor in the DJ Basin, delivers NGLs to our fractionation facilities under a long-term fractionation agreement. Our storage facility in Marysville, Michigan provides storage and related services primarily to regional refining and petrochemical companies and NGL marketers operating in the liquid hydrocarbons industry.
Wholesale Propane Logistics Segment
We operate a wholesale propane logistics business in the mid-Atlantic, upper midwest and northeastern United States. We purchase large volumes of propane supply from natural gas processing plants and fractionation facilities, and crude oil refineries, primarily located in the Texas and Louisiana Gulf Coast area, Canada and other international sources, and transport these volumes of propane supply by pipeline, rail or ship to our terminals and storage facilities in the mid-Atlantic, midwest and the northeastern areas of the United States. We identify primary suppliers as those individually representing 10% or more of our total propane supply. Our four primary suppliers of propane, one of which is an affiliated entity, represented approximately 85% of our propane supplied during the year ended December 31, 2013. We primarily sell propane on a wholesale basis to propane distributors who in turn resell propane to their customers. We also sell propane in the wholesale market.
Due to our multiple propane supply sources, annual and long-term propane supply purchase arrangements, significant storage capabilities, and multiple terminal locations for wholesale propane delivery, we are generally able to provide our propane distribution customers with reliable supplies of propane during periods of tight supply, such as the winter months when their customers generally consume the most propane for home heating. In particular, we generally offer our customers the ability to obtain propane supply volumes from us in the winter months that are generally significantly greater than their purchases of propane from us in the summer. We believe these factors allow us to maintain our generally favorable relationships with our customers.
We manage our wholesale propane margins by selling propane to propane distributors under annual sales agreements negotiated each spring which specify floating price terms that provide us a margin in excess of our floating index-based supply costs under our supply purchase arrangements. Our portfolio of multiple supply sources and storage capabilities allows us to actively manage our propane supply purchases and to lower the aggregate cost of supplies. Based on the carrying value of our inventory, timing of inventory transactions and the volatility of the market value of propane, we have historically and may continue to periodically recognize non-cash lower of cost or market inventory adjustments. In addition, we may use financial derivatives to manage the value of our propane inventories.
How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (1) volumes; (2) gross margin and segment gross margin; (3) operating and maintenance expense, and general and administrative expense; (4) adjusted EBITDA, (5) adjusted segment EBITDA; and (6) distributable cash flow. Gross margin, segment gross margin, adjusted EBITDA, adjusted segment EBITDA, and distributable cash flow are
not measures under accounting principles generally accepted in the United States of America, or GAAP. To the extent permitted, we present certain non-GAAP measures and reconciliations of those measures to their most directly comparable financial measures as calculated and presented in accordance with GAAP. These non-GAAP measures may not be comparable to a similarly titled measure of another company because other entities may not calculate these non-GAAP measures in the same manner.
Volumes - We view throughput and storage volumes for our Natural Gas Services segment and our NGL Logistics segment, and sales volumes for our Wholesale Propane Logistics segment as important factors affecting our profitability. We gather and transport some of the natural gas and NGLs under fee-based transportation contracts. Revenue from these contracts is derived by applying the rates stipulated to the volumes transported. Pipeline throughput volumes from existing wells connected to our pipelines will naturally decline over time as wells deplete. Accordingly, to maintain or to increase throughput levels on these pipelines and the utilization rate of our natural gas processing plants, we must continually obtain new supplies of natural gas and NGLs. Our ability to maintain existing supplies of natural gas and NGLs and obtain new supplies are impacted by: (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines; and (2) our ability to compete for volumes from successful new wells in other areas. The throughput volumes of NGLs and gas on our pipelines are substantially dependent upon the quantities of NGLs and gas produced at our processing plants, as well as NGLs and gas produced at other processing plants that have pipeline connections with our NGL and gas pipelines. We regularly monitor producer activity in the areas we serve and in which our pipelines are located, and pursue opportunities to connect new supply to these pipelines. We also monitor our inventory in our NGL and gas storage facilities, as well as overall demand for storage based on seasonal patterns and other market factors such as weather and overall demand.
Reconciliation of Non-GAAP Measures
Gross Margin and Segment Gross Margin — We view our gross margin as an important performance measure of the core profitability of our operations. We review our gross margin monthly for consistency and trend analysis.
We define gross margin as total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs, and we define segment gross margin for each segment as total operating revenues, including commodity derivative activity, for that segment less commodity purchases for that segment. Our gross margin equals the sum of our segment gross margins. Gross margin and segment gross margin are primary performance measures used by management, as these measures represent the results of product sales and purchases, a key component of our operations. As an indicator of our operating performance, gross margin and segment gross margin should not be considered an alternative to, or more meaningful than, operating revenues, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States of America, or GAAP.
Adjusted EBITDA — We define adjusted EBITDA as net income or loss attributable to partners less interest income, noncontrolling interest in depreciation and income tax expense and non-cash commodity derivative gains, plus interest expense, income tax expense, depreciation and amortization expense and non-cash commodity derivative losses. Our adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate this measure in the same manner.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations.
Adjusted EBITDA is used as a supplemental liquidity and performance measure and adjusted segment EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess:
| |
| • | financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
| |
| • | our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing methods or capital structure; |
| |
| • | viability and performance of acquisitions and capital expenditure projects and the overall rates of return on investment opportunities; and |
| |
| • | in the case of Adjusted EBITDA, the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, make cash distributions to our unitholders and general partner, and finance maintenance capital expenditures. |
Adjusted Segment EBITDA — We define adjusted segment EBITDA for each segment as segment net income or loss attributable to partners less non-cash commodity derivative gains for that segment, plus depreciation and amortization expense and non-cash commodity derivative losses for that segment, adjusted for any noncontrolling interest on depreciation and amortization expense for that segment. Our adjusted segment EBITDA may not be comparable to similarly titled measures of other companies because they may not calculate adjusted segment EBITDA in the same manner.
Adjusted segment EBITDA should not be considered in isolation or as an alternative to our financial measures presented in accordance with GAAP, including operating revenues, net income or loss attributable to Partners, or any other measure of performance presented in accordance with GAAP.
The accompanying schedules provide reconciliations of gross margin, segment gross margin and adjusted segment EBITDA to its most directly comparable GAAP financial measure.
Distributable Cash Flow — We define Distributable Cash Flow as net cash provided by or used in operating activities, less maintenance capital expenditures, net of reimbursable projects, plus or minus adjustments for non-cash mark-to-market of derivative instruments, proceeds from divestiture of assets, net income attributable to noncontrolling interest net of depreciation and income tax, net changes in operating assets and liabilities, and other adjustments to reconcile net cash provided by or used in operating activities. Maintenance capital expenditures are cash expenditures made to maintain our cash flows, operating or earnings capacity. These expenditures add on to or improve capital assets owned, including certain system integrity, compliance and safety improvements. Maintenance capital expenditures also include certain well connects, and may include the acquisition or construction of new capital assets. Non-cash mark-to-market of derivative instruments is considered to be non-cash for the purpose of computing Distributable Cash Flow because settlement will not occur until future periods, and will be impacted by future changes in commodity prices and interest rates. Distributable Cash Flow is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess our ability to make cash distributions to our unitholders and our general partner.
Our Distributable Cash Flow may not be comparable to a similarly titled measure of another company because other entities may not calculate Distributable Cash Flow in the same manner. Our gross margin, segment gross margin, adjusted EBITDA and adjusted segment EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate these measures in the same manner. The following table sets forth our reconciliation of certain non-GAAP measures:
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2013 | | 2012 | | 2011 |
| Reconciliation of Non-GAAP Measures | | (Millions) |
| | | | | | | |
| Reconciliation of net income attributable to partners to gross margin: | | | | | | |
| | | | | | | |
| Net income attributable to partners | | $ | 200 |
| | $ | 216 |
| | $ | 191 |
|
| Interest expense | | 52 |
| | 42 |
| | 34 |
|
| Income tax expense | | 8 |
| | 1 |
| | 1 |
|
| Operating and maintenance expense | | 215 |
| | 197 |
| | 192 |
|
| Depreciation and amortization expense | | 95 |
| | 91 |
| | 135 |
|
| General and administrative expense | | 63 |
| | 75 |
| | 76 |
|
| Other expense (income) | | 8 |
| | — |
| | (1 | ) |
| Earnings from unconsolidated affiliates | | (33 | ) | | (26 | ) | | (23 | ) |
| Net income attributable to noncontrolling interests | | 17 |
| | 13 |
| | 30 |
|
| Gross margin | | $ | 625 |
| | $ | 609 |
| | $ | 635 |
|
| Non-cash commodity derivative mark-to-market (a) | | $ | (37 | ) | | $ | 21 |
| | $ | 42 |
|
| | | | | | | |
| Reconciliation of segment net income attributable to partners to segment gross margin: | | | | | | |
| | | | | | | |
| Natural Gas Services segment: | | | | | | |
| Segment net income attributable to partners | | $ | 213 |
| | $ | 256 |
| | $ | 240 |
|
| Operating and maintenance expense | | 184 |
| | 166 |
| | 161 |
|
| Depreciation and amortization expense | | 87 |
| | 83 |
| | 124 |
|
| Other expense | | 1 |
| | — |
| | — |
|
| Earnings from unconsolidated affiliates | | (1 | ) | | (15 | ) | | (23 | ) |
| Net income attributable to noncontrolling interests | | 17 |
| | 13 |
| | 30 |
|
| Segment gross margin | | $ | 501 |
| | $ | 503 |
| | $ | 532 |
|
| Non-cash commodity derivative mark-to-market (a) | | $ | (36 | ) | | $ | 20 |
| | $ | 42 |
|
| | | | | | | |
| NGL Logistics segment: | | | | | | |
| Segment net income attributable to partners | | $ | 79 |
| | $ | 53 |
| | $ | 29 |
|
| Operating and maintenance expense | | 16 |
| | 16 |
| | 16 |
|
| Depreciation and amortization expense | | 6 |
| | 6 |
| | 8 |
|
| Other expense (income) | | 3 |
| | — |
| | (1 | ) |
| Earnings from unconsolidated affiliates | | (32 | ) | | (11 | ) | | — |
|
| Segment gross margin | | $ | 72 |
| | $ | 64 |
| | $ | 52 |
|
| | | | | | | |
| Wholesale Propane Logistics segment: | | | | | | |
| Segment net income attributable to partners | | $ | 31 |
| | $ | 25 |
| | $ | 33 |
|
| Operating and maintenance expense | | 15 |
| | 15 |
| | 15 |
|
| Depreciation and amortization expense | | 2 |
| | 2 |
| | 3 |
|
| Other expense | | 4 |
| | — |
| | — |
|
| Segment gross margin | | $ | 52 |
| | $ | 42 |
| | $ | 51 |
|
| Non-cash commodity derivative mark-to-market (a) | | $ | (1 | ) | | $ | 1 |
| | $ | — |
|
| |
| (a) | Non-cash commodity derivative mark-to-market is included in segment gross margin, along with cash settlements for our commodity derivative contracts. |
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2013 | | 2012 | | 2011 |
| | | (Millions) |
| Reconciliation of net income attributable to partners to adjusted segment EBITDA: | | | | | | |
| Natural Gas Services segment: | | | | | | |
| Segment net income attributable to partners (a) | | $ | 213 |
| | $ | 256 |
| | $ | 240 |
|
| Non-cash commodity derivative mark-to-market | | 36 |
| | (20 | ) | | (42 | ) |
| Depreciation and amortization expense | | 87 |
| | 83 |
| | 124 |
|
| Noncontrolling interest on depreciation and income tax | | (6 | ) | | (7 | ) | | (20 | ) |
| Adjusted Segment EBITDA | | $ | 330 |
| | $ | 312 |
| | $ | 302 |
|
| NGL Logistics segment: | | | | | | |
| Segment net income attributable to partners | | $ | 79 |
| | $ | 53 |
| | $ | 29 |
|
| Depreciation and amortization expense | | 6 |
| | 6 |
| | 8 |
|
| Adjusted Segment EBITDA | | $ | 85 |
| | $ | 59 |
| | $ | 37 |
|
| Wholesale Propane Logistics segment: | | | | | | |
| Segment net income attributable to partners (b) | | $ | 31 |
| | $ | 25 |
| | $ | 33 |
|
| Non-cash commodity derivative mark-to-market | | 1 |
| | (1 | ) | | — |
|
| Depreciation and amortization expense | | 2 |
| | 2 |
| | 3 |
|
| Adjusted Segment EBITDA | | $ | 34 |
| | $ | 26 |
| | $ | 36 |
|
| |
| (a) | Includes $2 million, $4 million and $5 million of lower of cost or market adjustments for the years ended December 31, 2013, 2012, and 2011, respectively. |
| |
| (b) | Includes $2 million, $15 million and $1 million of lower of cost or market adjustments for the years ended December 31, 2013, 2012, and 2011, respectively. |
Operating and Maintenance and General and Administrative Expense - Operating and maintenance expenses are costs associated with the operation of a specific asset and are primarily comprised of direct labor, ad valorem taxes, repairs and maintenance, lease expenses, utilities and contract services. These expenses fluctuate depending on the activities performed during a specific period. General and administrative expenses are as follows:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| General and administrative expense | $ | 17 |
| | $ | 17 |
| | $ | 19 |
|
| General and administrative expense - affiliate: | | | | | |
| Services/Omnibus Agreement | 29 |
| | 26 |
| | 10 |
|
| Other - DCP Midstream, LLC | 17 |
| | 32 |
| | 47 |
|
| Total affiliate | 46 |
| | 58 |
| | 57 |
|
| Total | $ | 63 |
| | $ | 75 |
| | $ | 76 |
|
We have entered into a services agreement, as amended, or the Services Agreement, with DCP Midstream, LLC. Under the Services Agreement, which replaced the Omnibus Agreement on February 14, 2013, we are required to reimburse DCP Midstream, LLC for salaries of operating personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also pay DCP Midstream, LLC an annual fee under the Services Agreement for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. Except with respect to the annual fee, there is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for other expenses and expenditures incurred or payments made on our behalf. Pursuant to the Services Agreement, we will reimburse DCP Midstream, LLC for expenses and expenditures incurred or payments made on our behalf.
In addition to the fees paid pursuant to the Services and Omnibus Agreements, we incurred allocated expenses, including insurance and internal audit fees with DCP Midstream, LLC of $2 million for the year ended December 31, 2013 and $1 million for each of the years ended December 31, 2012 and 2011, respectively. The Lucerne 1 plant incurred $1 million in general and administrative expenses directly from DCP Midstream, LLC for each of the years ended December 31, 2013, 2012 and 2011. The Eagle Ford system incurred $14 million for the year ended December 31, 2013 and $27 million for each of the years ended December 31, 2012 and 2011, respectively, in general and administrative expenses directly from DCP Midstream, LLC, which relates to the difference in the Eagle Ford system's ownership structure during these periods. For the years ended December 31, 2012 and 2011, Southeast Texas incurred $3 million and $10 million in general and administrative expenses directly from DCP Midstream, LLC, before the addition of Southeast Texas to the Omnibus Agreement in March 2012. During the year ended December 31, 2011, East Texas incurred $8 million in general and administrative expenses directly from DCP Midstream, LLC.
We also incurred third party general and administrative expenses, which were primarily related to compensation and benefit expenses of the personnel who provide direct support to our operations. Also included are expenses associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, due diligence and acquisition costs, costs associated with the Sarbanes-Oxley Act of 2002, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and director compensation.
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2013, 2012, and 2011. The results of operations by segment are discussed in further detail following this consolidated overview discussion:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | Variance
2013 vs. 2012 | | Variance 2012 vs. 2011 |
| | | 2013
(a)(b) | | 2012
(a)(b)(c) | | 2011
(a)(b)(c) | | Increase
(Decrease) | | Percent | | Increase (Decrease) | | Percent |
| | (Millions, except operating data) |
| Operating revenues (d): | | | | | | | | | | | | | | |
| Natural Gas Services | | $ | 2,598 |
| | $ | 2,345 |
| | $ | 3,102 |
| | $ | 253 |
| | 11 | % | | $ | (757 | ) | | (24 | )% |
| NGL Logistics | | 73 |
| | 64 |
| | 57 |
| | 9 |
| | 14 | % | | 7 |
| | 12 | % |
| Wholesale Propane Logistics | | 380 |
| | 415 |
| | 633 |
| | (35 | ) | | (8 | )% | | (218 | ) | | (34 | )% |
| Intra-segment eliminations | | — |
| | — |
| | (2 | ) | | — |
| | — | % | | 2 |
| | 100 | % |
| Total operating revenues | | 3,051 |
| | 2,824 |
| | 3,790 |
| | 227 |
| | 8 | % | | (966 | ) | | (25 | )% |
| Gross margin (e): | | | | | | | |
| |
| | | |
|
| Natural Gas Services | | 501 |
| | 503 |
| | 532 |
| | (2 | ) | | — | % | | (29 | ) | | (5 | )% |
| NGL Logistics | | 72 |
| | 64 |
| | 52 |
| | 8 |
| | 13 | % | | 12 |
| | 23 | % |
| Wholesale Propane Logistics | | 52 |
| | 42 |
| | 51 |
| | 10 |
| | 24 | % | | (9 | ) | | (18 | )% |
| Total gross margin | | 625 |
| | 609 |
| | 635 |
| | 16 |
| | 3 | % | | (26 | ) | | (4 | )% |
| Operating and maintenance expense | | (215 | ) | | (197 | ) | | (192 | ) | | 18 |
| | 9 | % | | 5 |
| | 3 | % |
| Depreciation and amortization expense | | (95 | ) | | (91 | ) | | (135 | ) | | 4 |
| | 4 | % | | (44 | ) | | (33 | )% |
| General and administrative expense | | (63 | ) | | (75 | ) | | (76 | ) | | (12 | ) | | (16 | )% | | (1 | ) | | (1 | )% |
| Other (expense) income | | (8 | ) | | — |
| | 1 |
| | 8 |
| | 100 | % | | (1 | ) | | (100 | )% |
| Earnings from unconsolidated affiliates (f) | | 33 |
| | 26 |
| | 23 |
| | 7 |
| | 27 | % | | 3 |
| | 13 | % |
| Interest expense | | (52 | ) | | (42 | ) | | (34 | ) | | 10 |
| | 24 | % | | 8 |
| | 24 | % |
| Income tax expense | | (8 | ) | | (1 | ) | | (1 | ) | | 7 |
| | 700 | % | | — |
| | — | % |
| Net income attributable to noncontrolling interests | | (17 | ) | | (13 | ) | | (30 | ) | | 4 |
| | 31 | % | | (17 | ) | | (57 | )% |
| Net income attributable to partners | | $ | 200 |
| | $ | 216 |
| | $ | 191 |
| | $ | (16 | ) | | (7 | )% | | $ | 25 |
| | 13 | % |
| Other data: | | | | | | | |
| |
| |
| |
|
| Non-cash commodity derivative mark-to-market | | $ | (37 | ) | | $ | 21 |
| | $ | 42 |
| | $ | (58 | ) | | (276 | )% | | $ | (21 | ) | | (50 | )% |
| Natural gas throughput (MMcf/d) (g) | | 2,307 |
| | 2,359 |
| | 1,990 |
| | (52 | ) | | (2 | )% | | 369 |
| | 19 | % |
| NGL gross production (Bbls/d) (g) | | 121,970 |
| | 115,945 |
| | 90,295 |
| | 6,025 |
| | 5 | % | | 25,650 |
| | 28 | % |
| NGL pipelines throughput (Bbls/d) (g) | | 89,361 |
| | 78,508 |
| | 62,555 |
| | 10,853 |
| | 14 | % | | 15,953 |
| | 26 | % |
| Propane sales volume (Bbls/d) | | 19,553 |
| | 19,111 |
| | 24,743 |
| | 442 |
| | 2 | % | | (5,632 | ) | | (23 | )% |
| |
| (a) | Includes our Lucerne 1 plant, retrospectively adjusted. We acquired the Lucerne 1 plant on March 28, 2014. |
| |
| (b) | Includes our 80% interest in the Eagle Ford system, retrospectively adjusted. We acquired a 33.33% interest in the Eagle Ford system on November 2, 2012, and a 46.67% interest on March 28, 2013. |
| |
| (c) | Includes our 100% interest in Southeast Texas, retrospectively adjusted. We acquired a 33.33% interest in Southeast Texas on January 1, 2011, and a 66.67% interest on March 30, 2012. |
| |
| (d) | Operating revenues include the impact of commodity derivative activity. |
| |
| (e) | Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Segment gross margin for each segment consists of total operating revenues for that segment, less commodity purchases for that segment. Please read “Reconciliation of Non-GAAP Measures” above. |
| |
| (f) | Includes our share, based on our ownership percentage, of the earnings of all unconsolidated affiliates which include our 40% ownership of Discovery, 20% ownership of the Mont Belvieu 1 fractionator, 12.5% ownership of the Mont Belvieu Enterprise fractionator and 10% ownership of Texas Express. Earnings for Discovery, the Mont Belvieu 1 fractionator and Texas Express include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the entities. |
| |
| (g) | Includes our share, based on our ownership percentage, of the throughput volumes and NGL production of unconsolidated affiliates. |
Year Ended December 31, 2013 vs. Year Ended December 31, 2012
Total Operating Revenues — Total operating revenues increased $227 million in 2013 compared to 2012 as a result of the following:
| |
| • | $253 million increase for our Natural Gas Services segment primarily due to higher volumes, an increase attributable to commodity prices and an increase in fee revenue, partially offset by a decrease in commodity derivative activity related to hedge settlement timing on our natural gas storage and pipeline assets; and |
| |
| • | $9 million increase for our NGL Logistics segment primarily due to increased throughput on certain of our pipelines and increased activity at our NGL storage facility. |
These increases were partially offset by:
| |
| • | $35 million decrease for our Wholesale Propane Logistics segment primarily due to lower propane prices and commodity derivative activity related to favorable hedge settlement timing in 2012, partially offset by increased volumes. |
Gross Margin — Gross margin increased $16 million in 2013 compared to 2012, primarily as a result of the following.
| |
| • | $10 million increase for our Wholesale Propane Logistics segment, primarily due to increased unit margins and exporting of propane, partially offset by a decrease related to commodity derivative activity. 2012 results reflect a non-cash lower of cost or market inventory adjustment and reduced demand; and |
| |
| • | $8 million increase for our NGL Logistics segment as a result of increased throughput on certain of our pipelines and increased activity at our NGL storage facility. |
These increases were partially offset by:
| |
| • | $2 million decrease for our Natural Gas Services segment, primarily related to decreased commodity derivative activity, lower commodity prices and lower volumes across certain assets, partially offset by improved NGL recoveries and an annual minimum volume commitment fee at our Eagle Ford system, a decrease in a lower of cost or market adjustment recognized in 2013 and extensive turnaround activity at our East Texas system in 2012. |
Operating and Maintenance Expense — Operating and maintenance expense increased in 2013 compared to 2012 primarily as a result of growth and asset reliability expenditures.
Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2013 compared to 2012 primarily as a result of growth in our business, partially offset by a change in the estimated depreciable lives of our fixed assets in the second quarter of 2012. The key contributing factors to the change in depreciable lives was an increase in the producers’ estimated remaining economically recoverable reserves, resulting from widespread application of techniques, such as hydraulic fracturing and horizontal drilling, that improve commodity production in the regions our assets serve. Advances in extraction processes, along with improved technology used to locate commodity reserves, is giving producers greater access to unconventional commodities.
General and Administrative Expense — General and administrative expense decreased in 2013 compared to 2012 primarily due to the difference in the Eagle Ford system's ownership structure in each period.
Other Expense — Other expense represents a write off of approximately $8 million in construction work in progress in 2013 due to discontinued projects.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2013 compared to 2012 primarily as a result of increased volumes in our NGL Logistics segment, in part due to the acquisition of the Mont Belvieu fractionators in July 2012. 2012 results for the Mont Belvieu 1 fractionator reflect lower margin and higher operating expenses. This increase was partially offset by lower NGL prices and volumes, a non-cash write off of fixed assets, a third party outage
and higher operating expenses at Discovery. 2012 results for Discovery reflect the favorable settlement of commercial disputes.
Interest Expense — Interest expense increased in 2013 compared to 2012 as a result of higher outstanding debt balances.
Income Tax Expense — Income tax expense increased in 2013 compared to 2012 primarily due to growth in our business.
Net Income Attributable to Noncontrolling Interests — Net income attributable to noncontrolling interests increased in 2013 compared to 2012, primarily as a result of higher volumes, improved NGL recoveries and an annual minimum volume commitment fee at our Eagle Ford system.
Year Ended December 31, 2012 vs. Year Ended December 31, 2011
Total Operating Revenues — Total operating revenues decreased $966 million in 2012 compared to 2011 primarily as a result of the following:
| |
| • | $757 million decrease for our Natural Gas Services segment primarily due to lower commodity prices in 2012 and the East Texas recovery settlement in 2011, partially offset by increases related to commodity derivative activity, fee revenue and volumes; and |
| |
| • | $218 million decrease for our Wholesale Propane Logistics segment due to lower volumes and prices, partially offset by an increase related to commodity derivative activity. |
These decreases were partially offset by:
| |
| • | $9 million increase for our NGL Logistics segment due to an increase in volumes. |
Gross Margin — Gross margin decreased $26 million in 2012 compared to 2011, primarily as a result of the following:
| |
| • | $29 million decrease for our Natural Gas Services segment, primarily related to lower commodity prices, the East Texas recovery settlement in 2011 and decreased volumes and differences in gas quality across certain assets, partially offset by increased commodity derivative activity and increased volumes across certain assets; and |
| |
| • | $9 million decrease for our Wholesale Propane Logistics segment primarily from a lack of demand. |
These decreases were partially offset by:
| |
| • | $12 million increase for our NGL Logistics segment primarily as a result of increased throughput and rates on certain of our assets and our acquisition of the DJ Basin NGL fractionators, partially offset by lower volumes at certain connected processing facilities due to ethane rejection. |
Operating and Maintenance Expense - Operating and maintenance expense increased in 2012 compared to 2011 primarily as a result of our acquisition of the Crossroads system in July 2012, turnaround activity at our Eagle Ford system and increased costs associated with the organic growth projects completed in 2011 at our Eagle Ford system.
Depreciation and Amortization Expense - Depreciation and amortization expense decreased in 2012 compared to 2011 primarily as a result of a change in the estimated useful lives of our assets. The key contributing factors to the change in depreciable lives was an increase in the producers’ estimated remaining economically recoverable reserves, resulting from widespread application of techniques, such as hydraulic fracturing and horizontal drilling, that improve commodity production in the regions our assets serve. Advances in extraction processes, along with improved technology used to locate commodity reserves, is giving producers greater access to unconventional commodities.
Earnings from Unconsolidated Affiliates - Earnings from unconsolidated affiliates, increased in 2012 compared to 2011 primarily as a result of our acquisition of the Mont Belvieu Fractionators in July 2012.
Net Income Attributable to Noncontrolling Interests - Net income attributable to noncontrolling interests decreased in 2012 compared to 2011 as a result of our acquisition of the remaining 49.9% of our East Texas system.
Results of Operations — Natural Gas Services Segment
This segment consists of our 80% interest in the Eagle Ford system, our 100% owned Eagle Plant, our East Texas system, our Southeast Texas system, our Michigan system, our Northern Louisiana system, our Southern Oklahoma system, our Wyoming system, our 75% interest in the Piceance system, our 40% interest in Discovery, and our DJ Basin system which consists of the O'Connor and Lucerne 1 plants:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | Variance
2013 vs. 2012 | | Variance 2012 vs. 2011 |
| | | 2013 (a)(b) | | 2012 (a)(b)(c) | | 2011
(a)(b)(c) | | Increase (Decrease) | | Percent | | Increase (Decrease) | | Percent |
| | (Millions, except operating data) |
| Operating revenues: | | | | | | | | | | | | | | |
| Sales of natural gas, NGLs and condensate | | $ | 2,383 |
| | $ | 2,123 |
| | $ | 2,937 |
| | $ | 260 |
| | 12 | % | | $ | (814 | ) | | (28 | )% |
| Transportation, processing and other | | 199 |
| | 170 |
| | 156 |
| | 29 |
| | 17 | % | | 14 |
| | 9 | % |
| Gains from commodity derivative activity | | 16 |
| | 52 |
| | 9 |
| | (36 | ) | | (69 | )% | | 43 |
| | 478 | % |
| Total operating revenues | | 2,598 |
| | 2,345 |
| | 3,102 |
| | 253 |
| | 11 | % | | (757 | ) | | (24 | )% |
| Purchases of natural gas and NGLs | | (2,097 | ) | | (1,842 | ) | | (2,570 | ) | | 255 |
| | 14 | % | | (728 | ) | | (28 | )% |
| Segment gross margin (d) | | 501 |
| | 503 |
| | 532 |
| | (2 | ) | | — | % | | (29 | ) | | (5 | )% |
| Operating and maintenance expense | | (184 | ) | | (166 | ) | | (161 | ) | | 18 |
| | 11 | % | | 5 |
| | 3 | % |
| Depreciation and amortization expense | | (87 | ) | | (83 | ) | | (124 | ) | | 4 |
| | 5 | % | | (41 | ) | | (33 | )% |
| Other expense | | (1 | ) | | — |
| | — |
| | 1 |
| | 100 | % | | — |
| | — | % |
| Earnings from unconsolidated affiliates (e) | | 1 |
| | 15 |
| | 23 |
| | (14 | ) | | (93 | )% | | (8 | ) | | (35 | )% |
| Segment net income | | 230 |
| | 269 |
| | 270 |
| | (39 | ) | | (14 | )% | | (1 | ) | | — | % |
| Segment net income attributable to noncontrolling interests | | (17 | ) | | (13 | ) | | (30 | ) | | 4 |
| | 31 | % | | (17 | ) | | (57 | )% |
| Segment net income attributable to partners | | $ | 213 |
| | $ | 256 |
| | $ | 240 |
| | $ | (43 | ) | | (17 | )% | | $ | 16 |
| | 7 | % |
| Other data: | | | | | | | | | | | | | | |
| Non-cash commodity derivative mark-to-market | | $ | (36 | ) | | $ | 20 |
| | $ | 42 |
| | $ | (56 | ) | | (280 | )% | | $ | (22 | ) | | (52 | )% |
| Natural gas throughput (MMcf/d) (f) | | 2,307 |
| | 2,359 |
| | 1,990 |
| | (52 | ) | | (2 | )% | | 369 |
| | 19 | % |
| NGL gross production (Bbls/d) (f) | | 121,970 |
| | 115,945 |
| | 90,295 |
| | 6,025 |
| | 5 | % | | 25,650 |
| | 28 | % |
| |
| (a) | Includes our Lucerne 1 plant, retrospectively adjusted. We acquired the Lucerne 1 plant on March 28, 2014. |
| |
| (b) | Includes our 80% interest in the Eagle Ford system, retrospectively adjusted. We acquired a 33.33% interest in the Eagle Ford system on November 2, 2012, and a 46.67% interest on March 28, 2013. |
| |
| (c) | Includes our 100% interest in Southeast Texas, retrospectively adjusted. We acquired a 33.33% interest in Southeast Texas on January 1, 2011, and a 66.67% interest on March 30, 2012. |
| |
| (d) | Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas and NGLs. Please read “Reconciliation of Non-GAAP Measures” above. |
| |
| (e) | Includes our share, based on our ownership percentage, of the earnings of all unconsolidated affiliates which include our 40% ownership of Discovery. Earnings for Discovery include the amortization of the net difference between the carrying amount of our investment and the underlying equity of the entity. |
| |
| (f) | Includes our share, based on our ownership percentage, of the throughput volumes and NGL production of unconsolidated affiliates. |
Year Ended December 31, 2013 vs. Year Ended December 31, 2012
Total Operating Revenues — Total operating revenues increased $253 million in 2013 compared to 2012, primarily as a result of the following:
| |
| • | $209 million increase primarily attributable to higher volumes and improved NGL recoveries at our Eagle Ford and East Texas systems, partially offset by lower volumes across certain assets, primarily our Southeast Texas system, and a plant turnaround at our Eagle Ford system. 2012 results reflect extensive turnaround activity at our East Texas system; |
| |
| • | $183 million increase attributable to increased natural gas prices; |
| |
| • | $83 million increase attributable to increased prices related to our natural gas storage and pipeline assets at our Southeast Texas and Northern Louisiana systems; and |
| |
| • | $29 million increase in fee revenue primarily attributable to higher volumes at our Eagle Ford and East Texas systems, and the operation of our O'Connor plant. |
These increases were partially offset by:
| |
| • | $145 million decrease attributable to decreased NGL prices; |
| |
| • | $70 million decrease attributable to decreased volumes related to our natural gas storage and pipeline assets at our Southeast Texas and Northern Louisiana systems; and |
| |
| • | $36 million decrease related to commodity derivative activity. This includes unrealized commodity derivative losses in 2013 compared to gains in 2012 due to movements in forward prices of commodities for a net impact of $56 million, partially offset by an increase in realized cash settlement gains in 2013 compared to 2012 of $20 million. |
Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs increased $255 million in 2013 compared to 2012 primarily as a result of higher natural gas prices, increased volumes at our Eagle Ford and East Texas systems and extensive turnaround activity at our East Texas system in 2012, partially offset by decreased NGL prices, decreased volumes related to our natural gas storage and pipeline assets at our Southeast Texas and Northern Louisiana systems, lower volumes across certain gathering and processing assets, primarily our Southeast Texas system, and a plant turnaround at our Eagle Ford system.
Segment Gross Margin — Segment gross margin decreased $2 million in 2013 compared to 2012, primarily as a result of the following:
| |
| • | $36 million decrease related to commodity derivative activity as discussed above; |
| |
| • | $24 million decrease as a result of lower NGL prices, which primarily reflects the unhedged portion of the Eagle Ford system associated with DCP Midstream, LLC’s ownership during the year ended December 31, 2013; and |
| |
| • | $2 million decrease attributable to lower volumes associated with our natural gas storage and pipeline assets at our Southeast Texas and Northern Louisiana systems; partially offset by a decrease in the lower of cost or market adjustment recognized in 2013 as compared to 2012. |
These decreases were partially offset by:
| |
| • | $60 million increase as a result of growth from the operation of our fee-based O'Connor plant, higher volumes and improved NGL recoveries at our Eagle Ford and East Texas systems and an annual minimum volume commitment fee at our Eagle Ford system, partially offset by lower volumes across certain assets. 2012 results reflected extensive turnaround activity at our East Texas system. |
Operating and Maintenance Expense — Operating and maintenance expense increased in 2013 compared to 2012 primarily as a result of growth and asset reliability expenditures.
Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2013 compared to 2012 primarily as a result of growth in our business, offset by a change in the estimated depreciable lives of our fixed assets in the second quarter of 2012. The key contributing factors to the change in depreciable lives was an increase in the producers’ estimated remaining economically recoverable reserves, resulting from widespread application of techniques, such as hydraulic fracturing and horizontal drilling, that improve commodity production in the regions our assets serve. Advances in extraction processes, along with improved technology used to locate commodity reserves, is giving producers greater access to unconventional commodities.
Other Expense — Other expense represents a write off of approximately $1 million in construction work in progress in 2013 due to discontinued projects.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, primarily representing our 40% ownership of Discovery, decreased in 2013 compared to 2012 as a result of lower NGL prices, reduced throughput volumes, a non-cash write off of fixed assets, a third party outage and higher operating expenses, partially offset by a foreign currency translation gain related to the Keathley Canyon project. 2012 results reflect the favorable settlement of commercial disputes. Commodity derivative activity associated with our exposure on our unconsolidated affiliates is included in segment gross margin.
Segment Net Income Attributable to Noncontrolling Interests - Segment net income attributable to noncontrolling interests increased in 2013 compared to 2012, primarily as a result of higher volumes, improved NGL recoveries and an annual minimum volume commitment fee at our Eagle Ford system.
Natural Gas Throughput - Natural gas throughput decreased slightly in 2013 compared to 2012 primarily as a result of lower volumes across certain assets, partially offset by higher volumes due to the operation of our 100% owned Eagle and O'Connor plants in 2013, and extensive turnaround activity at our East Texas system in 2012.
NGL Gross Production - NGL production increased in 2013 compared to 2012 primarily as a result of higher volumes due to the operation of our 100% owned Eagle and O'Connor plants, and improved NGL recoveries at our Eagle Ford and East Texas systems, partially offset by lower volumes across certain assets. 2012 results reflect lower volumes as certain of our assets were required to curtail NGL production due to a downstream outage and extensive turnaround activity at our East Texas system.
Year Ended December 31, 2012 vs. Year Ended December 31, 2011
Total Operating Revenues — Total operating revenues decreased $757 million in 2012 compared to 2011, primarily as a result of the following:
| |
| • | $645 million decrease attributable to the impact of lower commodity prices on our gathering and processing business; |
| |
| • | $167 million decrease primarily attributable to decreased prices for physical sales related to our natural gas storage and pipeline assets, as well as a decrease in volumes; and |
| |
| • | $6 million decrease as a result of the East Texas recovery settlement in 2011. |
These decreases were partially offset by:
| |
| • | $43 million increase related to commodity derivative activity. This includes a change in unrealized commodity derivative activity in 2012 compared to 2011 of $22 million due to movements in forward prices of commodities, and realized cash settlement gains in 2012 compared to realized cash settlement losses in 2011 for a net increase of $65 million. Included in our derivative activity are an increase in unrealized losses of $38 million and an increase in realized gains of $33 million from the predecessor’s Southeast Texas storage business; |
| |
| • | $14 million in fee revenue primarily attributable to contractual amendments such that certain revenues changed from a gross presentation to a net fee presentation; and |
| |
| • | $4 million increase primarily attributable to increased volumes at our Eagle Ford system, partially offset by decreased volumes across certain assets, differences in gas quality and extensive turnaround activity at our East Texas system. |
Purchases of Natural Gas and NGLs - Purchases of natural gas and NGLs decreased $728 million in 2012 compared to 2011 primarily as a result of higher natural gas prices, increased volumes at our Eagle Ford system and across certain assets, partially offset by contractual amendments such that certain revenues changed from a gross presentation to a net fee presentation, decreased NGL prices and a plant turnaround at our Eagle Ford system.
Segment Gross Margin — Segment gross margin decreased $29 million in 2012 compared to 2011, primarily as a result of the following:
| |
| • | $102 million decrease as a result of lower commodity prices; and |
| |
| • | $6 million decrease as a result of the East Texas recovery settlement in 2011. |
These decreases were partially offset by:
| |
| • | $43 million increase related to commodity derivative activities as discussed in the Operating Revenues section above; and |
| |
| • | $36 million increase primarily attributable to increased volumes at our Eagle Ford system, partially offset by decreased volumes and differences in gas quality across certain assets, and extensive turnaround activity at our East Texas system. |
Operating and Maintenance Expense - Operating and maintenance expense increased in 2012 compared to 2011 primarily as a result of our acquisition of the Crossroads system in July 2012, turnaround activity at our Eagle Ford system and increased costs associated with the organic growth projects completed in 2011 at our Eagle Ford system.
Depreciation and Amortization Expense - Depreciation and amortization expense decreased in 2012 compared to 2011 primarily as a result of a change in the estimated useful lives of our assets. The key contributing factors to the change in depreciable lives was an increase in the producers’ estimated remaining economically recoverable reserves, resulting from widespread application of techniques, such as hydraulic fracturing and horizontal drilling, that improve commodity production in the regions our assets serve. Advances in extraction processes, along with improved technology used to locate commodity reserves, is giving producers greater access to unconventional commodities.
Earnings from Unconsolidated Affiliates - Earnings from unconsolidated affiliates, primarily representing our 40% ownership of Discovery, decreased in 2012 compared to 2011 primarily as a result of lower commodity prices and reduced throughput volumes on Discovery, partially offset by the timing of expenditures at Discovery. Commodity derivative activity associated with our exposure on our unconsolidated affiliates is included in segment gross margin.
Segment Net Income Attributable to Noncontrolling Interests - Segment net income attributable to noncontrolling interests decreased in 2012 compared to 2011 as a result of the acquisition of the remaining 49.9% of the East Texas system.
Natural Gas Throughput - Natural gas transported, processed and/or treated increased in 2012 compared to 2011 primarily as a result of our acquisition of the remaining 49.9% of the East Texas system and Crossroads system, partially offset by decreased volumes across certain assets and turnaround at our East Texas system.
NGL Gross Production - NGL production increased in 2012 compared to 2011 primarily as a result of our acquisition of the remaining 49.9% of the East Texas system and Crossroads system, partially offset by decreased volumes and differences in gas quality across certain assets and turnaround at East Texas.
Results of Operations — NGL Logistics Segment
This segment includes the NGL storage facility in Michigan, our 20% interest in the Mont Belvieu 1 fractionator, our 12.5% interest in the Mont Belvieu Enterprise fractionator, the Black Lake and Wattenberg interstate NGL pipelines, the DJ Basin NGL fractionators in Colorado, the Seabreeze and Wilbreeze intrastate NGL pipeline, our 33.33% interest in the Front Range interstate NGL pipeline (under construction as of December 31, 2013), and our 10% interest in the Texas Express intrastate NGL pipeline:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | Variance
2013 vs. 2012 | | Variance 2012 vs. 2011 |
| | | 2013 | | 2012 | | 2011 | | Increase (Decrease) | | Percent | | Increase (Decrease) | | Percent |
| | (Millions, except operating data) |
| Operating revenues: | | | | | | | | | | | | | | |
| Sales of NGLs | | $ | 1 |
| | $ | — |
| | $ | 5 |
| | $ | 1 |
| | 100 | % | | $ | (5 | ) | | (100 | )% |
| Transportation, processing and other | | 72 |
| | 64 |
| | 52 |
| | 8 |
| | 13 | % | | 12 |
| | 23 | % |
| Total operating revenues | | 73 |
| | 64 |
| | 57 |
| | 9 |
| | 14 | % | | 7 |
| | 12 | % |
| Purchases of NGLs | | (1 | ) | | — |
| | (5 | ) | | 1 |
| | 100 | % | | (5 | ) | | (100 | )% |
| Segment gross margin (a) | | 72 |
| | 64 |
| | 52 |
| | 8 |
| | 13 | % | | 12 |
| | 23 | % |
| Operating and maintenance expense | | (16 | ) | | (16 | ) | | (16 | ) | | — |
| | — | % | | — |
| | — | % |
| Depreciation and amortization expense | | (6 | ) | | (6 | ) | | (8 | ) | | — |
| | — | % | | (2 | ) | | (25 | )% |
| Other (expense) income | | (3 | ) | | — |
| | 1 |
| | 3 |
| | 100 | % | | (1 | ) | | (100 | )% |
| Earnings from unconsolidated affiliates (b) | | 32 |
| | 11 |
| | — |
| | 21 |
| | 191 | % | | 11 |
| | 100 | % |
| Segment net income attributable to partners | | $ | 79 |
| | $ | 53 |
| | $ | 29 |
| | $ | 26 |
| | 49 | % | | $ | 24 |
| | 83 | % |
| Other data: | | | | | | | | | | | | | | |
| NGL pipelines throughput (Bbls/d) (c) | | 89,361 |
| | 78,508 |
| | 62,555 |
| | 10,853 |
| | 14 | % | | 15,953 |
| | 26 | % |
| |
| (a) | Segment gross margin consists of total operating revenues less purchases of NGLs. Please read “Reconciliation of Non-GAAP Measures” above. |
| |
| (b) | Includes our share, based on our ownership percentage, of the earnings of all unconsolidated affiliates which include our 20% ownership of the Mont Belvieu 1 fractionator, 12.5% ownership of the Mont Belvieu Enterprise fractionator and 10% ownership of Texas Express. Earnings for Mont Belvieu 1 and Texas Express include the amortization of the net difference between the carrying amount of our investments and the underlying equity of the entities. |
| |
| (c) | Includes our share, based on our ownership percentage, of the throughput volumes of unconsolidated affiliates. |
Year Ended December 31, 2013 vs. Year Ended December 31, 2012
Total Operating Revenues — Total operating revenues increased in 2013 compared to 2012 as result of increased throughput on certain of our pipelines and increased activity at our NGL storage facility.
Segment Gross Margin — Segment gross margin increased in 2013 compared to 2012 as result of increased throughput on certain of our pipelines and increased activity at our NGL storage facility.
Operating and Maintenance Expense — Operating and maintenance expense remained constant in 2013 compared to 2012.
Depreciation and Amortization Expense — Depreciation and amortization remained constant in 2013 compared to 2012.
Other Expense — Other expense represents a write off of approximately $3 million in construction work in progress in 2013 due to a discontinued project.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, representing 20% ownership of the Mont Belvieu 1 fractionator, 12.5% ownership of the Mont Belvieu Enterprise fractionator and 10% ownership of Texas Express, increased in 2013 compared to 2012 primarily as a result of the acquisition of the Mont Belvieu fractionators in July 2012 and the Mont Belvieu Enterprise fractionator de-bottleneck project in the third quarter of 2013. 2012 results for the Mont Belvieu 1 fractionator reflect lower margin and higher operating expenses related to a planned turnaround.
NGL Pipelines Throughput — NGL pipelines throughput increased in 2013 compared to 2012 as a result of volume growth on our pipelines.
Year Ended December 31, 2012 vs. Year Ended December 31, 2011
Total Operating Revenues — Total operating revenues increased in 2012 compared to 2011 as result of increased throughput and rates on certain of our pipelines, the completion of the Wattenberg capital expansion project, and our acquisition of the DJ Basin NGL fractionators, partially offset by lower throughput volumes due to ethane rejection at certain connected processing facilities.
Segment Gross Margin - Segment gross margin increased in 2012 compared to 2011 as result of increased throughput and rates on certain of our pipelines, the completion of the Wattenberg capital expansion project, and our acquisition of the DJ Basin NGL fractionators, partially offset by lower throughput volumes due to ethane rejection at certain connected processing facilities.
Operating and Maintenance Expense - Operating and maintenance expense remained relatively constant in 2012 compared to 2011due to the completion of the Wattenberg capital expansion project, and our acquisition of the DJ Basin NGL fractionators, offset by timing of expenditures.
Depreciation and Amortization Expense - Depreciation and amortization expense decreased in 2012 compared to 2011 primarily as a result of a change in the estimated useful lives of our assets. The key contributing factors to the change in depreciable lives was an increase in the producers’ estimated remaining economically recoverable reserves, resulting from widespread application of techniques, such as hydraulic fracturing and horizontal drilling, that improve commodity production in the regions our assets serve. Advances in extraction processes, along with improved technology used to locate commodity reserves, is giving producers greater access to unconventional commodities.
Earnings from Unconsolidated Affiliates - Earnings from unconsolidated affiliates, representing 20% ownership of the Mont Belvieu 1 Fractionator and 12.5% ownership of the Mont Belvieu Enterprise Fractionator, increased in 2012 compared to 2011 as a result the acquisition of the Mont Belvieu Fractionators in July 2012.
NGL Pipelines Throughput - NGL pipelines throughput increased in 2012 compared to 2011 as a result of volume growth on our pipelines and the completion of the Wattenberg capital expansion project, partially offset by lower throughput volumes due to ethane rejection at certain connected processing facilities.
Results of Operations — Wholesale Propane Logistics Segment
This segment consists of our propane terminals, which include six owned and operated rail terminals, one owned marine import terminal, one leased marine terminal, one pipeline terminal and access to several open-access propane pipeline terminals.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | Variance
2013 vs. 2012 | | Variance 2012 vs. 2011 |
| | | 2013 | | 2012 | | 2011 | | Increase (Decrease) | | Percent | | Increase (Decrease) | | Percent |
| | (Millions, except operating data) |
| Operating revenues: | | | | | | | | | | | | | | |
| Sales of propane | | $ | 379 |
| | $ | 397 |
| | $ | 634 |
| | $ | (18 | ) | | (5 | )% | | $ | (237 | ) | | (37 | )% |
| Gains (losses) from commodity derivative activity | | 1 |
| | 18 |
| | (1 | ) | | (17 | ) | | (94 | )% | | 19 |
| | * |
|
| Total operating revenues | | 380 |
| | 415 |
| | 633 |
| | (35 | ) | | (8 | )% | | (218 | ) | | (34 | )% |
| Purchases of propane | | (328 | ) | | (373 | ) | | (582 | ) | | (45 | ) | | (12 | )% | | (209 | ) | | (36 | )% |
| Segment gross margin (a) | | 52 |
| | 42 |
| | 51 |
| | 10 |
| | 24 | % | | (9 | ) | | (18 | )% |
| Operating and maintenance expense | | (15 | ) | | (15 | ) | | (15 | ) | | — |
| | — | % | | — |
| | — | % |
| Depreciation and amortization expense | | (2 | ) | | (2 | ) | | (3 | ) | | — |
| | — | % | | (1 | ) | | (33 | )% |
| Other expense | | (4 | ) | | — |
| | — |
| | 4 |
| | 100 | % | | — |
| | — | % |
| Segment net (loss) income attributable to partners | | $ | 31 |
| | $ | 25 |
| | $ | 33 |
| | $ | 6 |
| | 24 | % | | $ | (8 | ) | | (24 | )% |
| Other data: | | | | | | | | | | | | | | |
| Non-cash commodity derivative mark-to-market | | $ | (1 | ) | | $ | 1 |
| | $ | — |
| | $ | (2 | ) | | (200 | )% | | $ | 1 |
| | 100 | % |
| Propane sales volume (Bbls/d) | | 19,553 |
| | 19,111 |
| | 24,743 |
| | 442 |
| | 2 | % | | (5,632 | ) | | (23 | )% |
_________________
* Percentage change is not meaningful.
| |
| (a) | Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of propane. Please read “Reconciliation of Non-GAAP Measures” above. |
Year Ended December 31, 2013 vs. Year Ended December 31, 2012
Total Operating Revenues — Total operating revenues decreased by $35 million in 2013 compared to 2012, primarily as a result of the following:
| |
| • | $25 million decrease attributable to lower propane prices; and |
| |
| • | $17 million decrease related to commodity derivative activity. This includes a decrease in realized cash settlement gains in 2013 compared to 2012 of $16 million, and unrealized commodity derivative losses in 2013 of $1 million due to movements in forward prices of commodities. |
These decreases were partially offset by:
| |
| • | $7 million increase attributable to increased volumes in part due to the export of propane from our Chesapeake terminal in the first quarter of 2013. 2012 results reflect a lack of demand due to the industry’s excess inventory resulting from near record warm weather. |
Purchases of Propane — Purchases of propane decreased in 2013 compared to 2012 primarily due to lower propane prices, which impacts both sales and purchases, a 2012 non-cash lower of cost or market inventory adjustment of $15 million, partially offset by increased volumes due to the export of propane from our Chesapeake terminal in the first quarter of 2013 and reduced demand in 2012 due to the industry’s excess inventory resulting from near record warm weather.
Segment Gross Margin — Segment gross margin increased in 2013 compared to 2012 primarily due to increased unit margins and exporting propane from our Chesapeake terminal in the first quarter of 2013, partially offset by a $17 million decrease related to commodity derivative activities as discussed above. 2012 results reflect a non-cash lower of cost or market
inventory adjustment of $15 million and reduced demand due to the industry’s excess inventory resulting from near record warm weather.
Operating and Maintenance Expense — Operating and maintenance expense remained constant in 2013 compared to 2012.
Depreciation and Amortization Expense — Depreciation and amortization expense remained constant in 2013 compared to 2012.
Other Expense — Other expense represents a write off of approximately $4 million in construction work in progress in 2013 due to a discontinued project.
Propane Sales Volume — Propane sales volumes increased in 2013 compared to 2012 due to the export of propane from our Chesapeake terminal in the first quarter. 2012 results reflect a lack of demand due to the industry’s excess inventory resulting from near record warm weather.
Year Ended December 31, 2012 vs. Year Ended December 31, 2011
Total Operating Revenues — Total operating revenues decreased $218 million in 2012 compared to 2011, primarily as a result of the following:
| |
| • | $152 million decrease attributable to reduced sales volumes primarily as a result of a lack of demand due to the industry’s excess inventory resulting from record warm weather last heating season; and |
| |
| • | $85 million decrease attributable to lower propane prices. |
These decreases were partially offset by:
| |
| • | $19 million increase related to a change in unrealized commodity derivative activity of $1 million and a change in realized commodity derivative activity of $18 million. |
Purchases of Propane - Purchases of propane decreased in 2012 compared to 2011 primarily due to reduced volumes as a result of inventory build resulting from record warm weather last heating season and lower propane prices, partially offset by a non-cash lower of cost or market inventory adjustment of $15 million in 2012, offset by a significant recovery through the sale of inventory.
Segment Gross Margin - Segment gross margin decreased in 2012 compared to 2011 primarily from a lack of demand due to the industry’s excess inventory resulting from record warm weather last heating season and lower per unit margins. A non-cash lower of cost or market inventory adjustment of $15 million was offset by a significant recovery through the sale of inventory and hedging activity.
Operating and Maintenance Expense - Operating and maintenance expense remained relatively constant in 2012 compared to 2011.
Depreciation and Amortization Expense - Depreciation and amortization expense remained relatively constant in 2012 compared to 2011.
Propane Sales Volume - Propane sales volumes decreased in 2012 compared to 2011 as a result of a lack of demand due to the industry’s excess inventory resulting from record warm weather last heating season.
Liquidity and Capital Resources
We expect our sources of liquidity to include:
| |
| • | cash generated from operations; |
| |
| • | cash distributions from our unconsolidated affiliates; |
| |
| • | borrowings under our revolving Credit Agreement; |
| |
| • | issuance of commercial paper under our Commercial Paper Program; |
| |
| • | borrowings under term loans; |
| |
| • | issuance of additional common units, including issuances we may make to DCP Midstream, LLC; |
We anticipate our more significant uses of resources to include:
| |
| • | quarterly distributions to our unitholders and general partner; |
| |
| • | contributions to our unconsolidated affiliates to finance our share of their capital expenditures; |
| |
| • | business and asset acquisitions, including transactions with DCP Midstream, LLC; and |
| |
| • | collateral with counterparties to our swap contracts to secure potential exposure under these contracts, which may, at times, be significant depending on commodity price movements, and letters of credit we have posted. |
We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure and acquisition requirements, and quarterly cash distributions for the next twelve months. In the event these sources are not sufficient, we would reduce our discretionary spending.
We routinely evaluate opportunities for strategic investments or acquisitions. Future material investments or acquisitions may require that we obtain additional capital, assume third party debt or incur other long-term obligations. We have the option to utilize both equity and debt instruments as vehicles for the long-term financing of our investment activities and acquisitions.
Based on current and anticipated levels of operations, we believe we have adequate committed financial resources to conduct our ongoing business, although deterioration in our operating environment could limit our borrowing capacity, impact our credit ratings, raise our financing costs, as well as impact our compliance with our financial covenant requirements under our Credit Agreement.
Our Credit Agreement consists of a senior unsecured revolving credit facility with capacity of $1 billion, which matures on November 10, 2016. Our borrowing capacity may be limited by the Credit Agreement’s financial covenant requirements. Except in the case of a default, which would make the borrowings under the Credit Agreement fully callable, amounts borrowed under the Credit Agreement will not mature prior to the November 10, 2016 maturity date. In October 2013, we entered into a commercial paper program, or the Commercial Paper Program, which serves as an alternative source of funding and does not increase our current overall borrowing capacity. Amounts available under the Commercial Paper Program may be borrowed, repaid, and re-borrowed from time to time with the maximum aggregate principal amount of notes outstanding, combined with the amount outstanding under our revolving credit facility, not to exceed $1 billion in the aggregate. Amounts undrawn under our revolving credit facility are available to repay the unsecured commercial paper notes, or the Notes, if necessary. The maturities of the Notes will vary, but may not exceed 397 days from the date of issue. The proceeds of the issuances of the Notes are expected to be used for capital expenditures and other general partnership purposes. As of February 20, 2014, we had $445 million of commercial paper outstanding as short-term borrowings and had approximately $555 million of unused capacity under the Credit Agreement.
In March 2013, we issued $500 million of 3.875% 10-year Senior Notes due March 15, 2023. We received proceeds of $490 million, net of underwriters’ fees, related expenses and unamortized discounts totaling $10 million, which we used to fund a portion of the acquisition of an additional 46.67% interest in the Eagle Ford system.
During the year ended December 31, 2013, we issued 1,408,547 of our common units pursuant to an equity distribution agreement entered into in August 2011, or the 2011 equity distribution agreement. We received proceeds of $67 million, net of commissions and offering costs of $2 million, which were used to finance growth opportunities and for general corporate purposes. The 2011 equity distribution agreement provided for the offer and sale of common units having an aggregate offering amount of up to $150 million. As of December 31, 2013, no common units remain available for sale pursuant to this equity distribution agreement and we have deregistered the corresponding registration statement.
In November 2013, we entered into an equity distribution agreement, or the 2013 equity distribution agreement, with a group of financial institutions as sales agents. The agreement provides for the offer and sale from time to time, through our
sales agents, of common units having an aggregate offering amount of up to $300 million. During the year ended December 31, 2013, we issued 1,839,430 of our common units pursuant to the 2013 equity distribution agreement and received proceeds of $87 million, net of accrued commissions and offering costs of $1 million, which were used to finance growth opportunities and for general corporate purposes. As of December 31, 2013, approximately $212 million aggregate offering price of our common units remain available for sale pursuant to the 2013 equity distribution agreement.
In August 2013, we issued 9,000,000 common units at $50.04 per unit. We received proceeds of $434 million, net of offering costs.
In March 2013, we issued 12,650,000 common units at $40.63 per unit. We received proceeds of $494 million, net of offering costs.
In March 2013, we issued 2,789,739 common units to DCP Midstream, LLC as partial consideration for the additional 46.67% interest in the Eagle Ford system.
Changes in natural gas, NGL and condensate prices and the terms of our processing arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. We have mitigated a significant portion of our anticipated commodity price risk associated with the equity volumes from our gathering and processing activities through 2017 with fixed price commodity swaps. For additional information regarding our derivative activities, please read Item 7A. “Quantitative and Qualitative Disclosures about Market Risk”.
The counterparties to certain of our commodity swap contracts are investment-grade rated financial institutions. Under these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to the collateral thresholds are determined on a counterparty by counterparty basis, and are impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative crude oil and natural gas forward price curves, it is not practical to determine a pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same counterparty. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis. The counterparty to our remaining commodity swaps contracts is DCP Midstream, LLC.
Working Capital — Working capital is the amount by which current assets exceed current liabilities. Current assets are reduced by our quarterly distributions, which are required under the terms of our partnership agreement based on Available Cash, as defined in the partnership agreement. In general, our working capital is impacted by changes in the prices of commodities that we buy and sell, inventory levels, and other business factors that affect our net income and cash flows. Our working capital is also impacted by the timing of operating cash receipts and disbursements, borrowings of and payments on debt, capital expenditures, and increases or decreases in other long-term assets.
We had working capital liabilities of $220 million as of December 31, 2013, compared to working capital assets of $23 million as of December 31, 2012. Included in these working capital amounts are net derivative working capital assets of $51 million and $18 million as of December 31, 2013 and December 31, 2012, respectively. The change in working capital is primarily attributable to the factors described above, as well as our commercial paper borrowings. We expect that our future working capital requirements will be impacted by these same factors.
As of December 31, 2013, we had $12 million in cash and cash equivalents. Cash held by consolidated subsidiaries with noncontrolling interests totaled $1 million. The remaining cash balance was available for general partnership purposes.
Cash Flow — Operating, investing and financing activities were as follows:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (Millions) |
| Net cash provided by operating activities | $ | 345 |
| | $ | 102 |
| | $ | 417 |
|
| Net cash used in investing activities | $ | (1,387 | ) | | $ | (1,384 | ) | | $ | (538 | ) |
| Net cash provided by financing activities | $ | 1,052 |
| | $ | 1,276 |
| | $ | 122 |
|
Our predecessor’s sources of liquidity, prior to its acquisition by us, included cash generated from operations and funding from DCP Midstream, LLC. Our predecessor’s cash receipts were deposited in DCP Midstream, LLC’s bank accounts and all cash disbursements were made from these accounts. Cash transactions for our predecessor were handled by DCP Midstream, LLC and were reflected in partners�� equity as net changes in parent advances to predecessors from DCP Midstream, LLC.
Net Cash Provided by Operating Activities — The changes in net cash provided by operating activities are attributable to our net income adjusted for non-cash charges as presented in the consolidated statements of cash flows, and changes in working capital as discussed above.
We received $54 million for our net hedge cash settlements for the year ended December 31, 2013, of which less than $1 million was associated with rebalancing our portfolio, and approximately $49 million and $34 million for our net hedge cash settlements for the years ended December 31, 2012 and 2011.
We received cash distributions from unconsolidated affiliates of $39 million, $24 million and $25 million during the years ended December 31, 2013, 2012, and 2011, respectively. Distributions exceeded earnings by $6 million for the year ended December 31, 2013.
Net Cash Used in Investing Activities — Net cash used in investing activities during the year ended December 31, 2013 was comprised of: (1) acquisition expenditures of $782 million related to our acquisition of the additional 46.67% interest in the Eagle Ford system for $486 million, the O'Connor plant for $210 million and Front Range for $86 million; (2) capital expenditures of $363 million (our portion of which was $325 million and the noncontrolling interests portion was $38 million) consisting of construction of the Goliad plant, construction and expansion of the O'Connor plant, expansion and upgrades to our Southeast Texas complex, expansion of the Marysville NGL storage facility, expansion of our Chesapeake facility and other projects; and (3) investments in unconsolidated affiliates of $242 million consisting of $133 million to Discovery, $55 million to Texas Express, $48 million to Front Range and $6 million to Mont Belvieu Enterprise Fractionator.
Net cash used in investing activities during 2012 was comprised of: (1) acquisition expenditures of $745 million, of which $282 million is related to our acquisition of the initial 33.33% interest in the Eagle Ford system, $193 million is related to our acquisition of the remaining 66.67% interest in Southeast Texas, $120 million related to our acquisition of the remaining 49.9% interest in East Texas, $63 million related to our acquisition of Crossroads, $57 million related to the acquisition of the Goliad plant by the Eagle Ford system, and $30 million related to our acquisition of the Mont Belvieu fractionators; (2) capital expenditures of $484 million (of which our portion was $411 million and the noncontrolling interest holders’ portion and the reimbursable projects portion was $73 million); and (3) investments in unconsolidated affiliates of $158 million; partially offset by (4) proceeds from sales of assets of $2 million; and (5) a return of investment from unconsolidated affiliate of $1 million.
Net cash used in investing activities during 2011 was comprised of: (1) capital expenditures of $385 million (our portion of which was $322 million and the noncontrolling interest holders’ portion was $63 million), which includes $23 million of capital expenditures related to our Eagle Plant construction; (2) acquisition expenditures of $114 million, representing the carrying value of the net assets acquired, related to our acquisition of an initial 33.33% interest in Southeast Texas; (3) acquisition expenditures of $30 million related to our acquisition of our DJ Basin NGL fractionators and a payment of $8 million to the seller of Michigan Pipeline & Processing, LLC in relation to our contingent payment agreement; and (4) investments in unconsolidated affiliates of $8 million; partially offset by (5) proceeds from sales of assets of $5 million; and (6) a return of investment from unconsolidated affiliates of $2 million.
Net Cash Provided by Financing Activities — Net cash provided by financing activities during 2013 was comprised of: (1) proceeds from long-term debt of $1,957 million, offset by payments of $1,988 million, for net repayment of long-term debt of $31 million; (2) proceeds from the issuance of commercial paper of $335 million; (3) proceeds from the issuance of common units, net of offering costs, of $1,083 million; (4) contributions from noncontrolling interests of $46 million; (5) net change in advances to predecessor from DCP Midstream, LLC of $11 million; and (6) contributions from DCP Midstream, LLC of $1 million; partially offset by (7) distributions to our limited partners and general partner of $277 million; (8) excess purchase price over acquired interests and commodity hedges of $85 million; (9) distributions to noncontrolling interests of $24 million; (10) payment of deferred financing costs of $4 million; and (11) distributions to DCP Midstream, LLC of $3 million relating to capital expenditures for reimbursable projects.
During the year ended December 31, 2013, total outstanding indebtedness under our $1 billion Credit Agreement, which includes borrowings under our revolving credit facility and letters of credit issued under the Credit Agreement, was not less than $1 million and did not exceed $607 million. The weighted-average indebtedness outstanding under the revolving credit facility was $429 million, $201 million, $265 million and $130 million for the first, second, third and fourth quarters of 2013, respectively.
The weighted-average indebtedness outstanding under the Commercial Paper Program was $273 million for the fourth quarter of 2013.
As of December 31, 2013, we had unused capacity under the revolving credit facility of $664 million, all of which was available for general working capital purposes.
During the year ended December 31, 2013, we had the following movements on our revolving credit facility:
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| • | $494 million repayment financed by the issuance of 12,650,000 common units in March 2013; |
| |
| • | $434 million repayment financed by the issuance of 9,000,000 common units in August 2013; and |
| |
| • | $335 million repayment financed by borrowings under our Commercial Paper Program; partially offset by |
| |
| • | $209 million borrowings to fund the acquisition of the O'Connor plant; |
| |
| • | $363 million net borrowings for general working capital purposes; |
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| • | $86 million borrowings to fund the acquisition of the Front Range pipeline; and |
| |
| • | $80 million borrowings primarily to reimburse DCP Midstream, LLC for its proportionate share of the capital spent to date, at closing, by the Eagle Ford system for the construction of the Goliad plant and for preformation capital expenditures. |
Net cash provided by financing activities during 2012 was comprised of: (1) proceeds from long-term debt of $2,665 million, offset by payments of $1,792 million, for net borrowing of long-term debt of $873 million; (2) proceeds from the issuance of common units net of offering costs of $455 million; (3) net change in advances to predecessor from DCP Midstream, LLC of $336 million; (4) contributions from noncontrolling interest of $25 million; (5) contributions from DCP Midstream, LLC of $10 million; partially offset by (6) distributions to our limited partners and general partner of $181 million; (7) excess purchase price over acquired interests of $225 million (8) distributions to noncontrolling interests of $9 million; and (9) payment of deferred financing costs of $8 million.
During 2012, total outstanding indebtedness under our $1 billion Credit Agreement, which includes borrowings under our revolving credit facility and letters of credit issued under the Credit Agreement, was not less than $268 million and did not exceed $576 million. The weighted-average indebtedness outstanding under the Credit Agreement was $496 million, $369 million, $321 million and $455 million for the first, second, third and fourth quarters of 2012, respectively.
We had unused capacity, which is available for commitments under the Credit Agreement, of $732 million, $649 million, $699 million and $474 million at the end of the first, second, third and fourth quarters of 2012, respectively.
During 2012, we had the following movements on our revolving credit facility:
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| • | $63 million borrowing to fund the acquisition of the Crossroads system; and |
| |
| • | $199 million net borrowings for general working capital purposes; partially offset by |
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| • | $234 million repayment with proceeds from the issuance of 5,148,500 common units in March 2012. |
Net cash provided by financing activities during 2011 was comprised of: (1) proceeds from the issuance of common units, net of offering costs, of $170 million; (2) net borrowing of long-term debt of $99 million; (3) net change in advances to predecessor from DCP Midstream, LLC of $52 million; and (4) contributions from noncontrolling interests of $18 million; partially offset by (5) distributions to our unitholders and general partner of $132 million; (6) distributions to noncontrolling interests of $45 million; (7) excess purchase price over the acquired net assets of Southeast Texas of $36 million; and (8) payment of deferred financing costs of $4 million.
During 2011, total outstanding indebtedness under our $1 billion Credit Agreement, which includes borrowings under our revolving credit facility and letters of credit issued under the Credit Agreement, was not less than $426 million and did not exceed $591 million. The weighted-average indebtedness outstanding under the revolving credit facility was $519 million, $454 million, $484 million and $517 million for the first, second, third and fourth quarters of 2011, respectively.
We had unused capacity, which is available for commitments under the Credit Agreement of $424 million, $388 million,
$373 million and $502 million at the end of the first, second, third and fourth quarters of 2011, respectively.
During 2011, we had the following movements on our revolving credit facility:
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| • | $150 million borrowing to fund the acquisition of our initial 33.33% interest in Southeast Texas; |
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| • | $30 million borrowing to fund the purchase of the DJ Basin NGL fractionators; |
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| • | $30 million borrowing to fund the Marysville tax payment; |
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| • | $23 million borrowing to fund the purchase of certain tangible assets and land located in the Eagle Ford Shale; and |
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| • | $6 million net borrowings; partially offset by |
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| • | $140 million repayment financed by the issue of 3,596,636 common units in March 2011. |
We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders and general partner. See Note 12 of the Notes to Consolidated Financial Statements in Exhibit 99.3 to this Form 8-K.
Capital Requirements — The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of the following:
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| • | maintenance capital expenditures, which are cash expenditures to maintain our cash flows, operating or earnings capacity. These expenditures add on to or improve capital assets owned, including certain system integrity, compliance and safety improvements. Maintenance capital expenditures also include certain well connects, and may include the acquisition or construction of new capital assets; and |
| |
| • | expansion capital expenditures, which are cash expenditures to increase our cash flows, operating or earnings capacity. Expansion capital expenditures include acquisitions or capital improvements (where we add on to or improve the capital assets owned, or acquire or construct new gathering lines and well connects, treating facilities, processing plants, fractionation facilities, pipelines, terminals, docks, truck racks, tankage and other storage, distribution or transportation facilities and related or similar midstream assets). |
We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance capital expenditures of between $35 million and $45 million, and approved expenditures for expansion capital of between $500 million and $600 million, for the year ending December 31, 2014. Expansion capital expenditures include construction of Discovery’s Keathley Canyon Connector, which is shown as investments in unconsolidated affiliates, construction of the Lucerne 2 plant, the Marysville NGL storage project and expansion of our Chesapeake facility, among other projects. The board of directors may, at its discretion, approve additional growth capital during the year.
The following table summarizes our maintenance and expansion capital expenditures for our consolidated entities:
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| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2013 | | Year Ended December 31, 2012 |
| | Maintenance Capital Expenditures | | Expansion Capital Expenditures | | Total Consolidated Capital Expenditures | | Maintenance Capital Expenditures | | Expansion Capital Expenditures | | Total Consolidated Capital Expenditures |
| | (Millions) |
| Our portion | $ | 23 |
| | $ | 302 |
| | $ | 325 |
| | $ | 23 |
| | $ | 388 |
| | $ | 411 |
|
| Noncontrolling interest portion and reimbursable projects (a) | 2 |
| | 36 |
| | 38 |
| | 8 |
| | 65 |
| | 73 |
|
| Total | $ | 25 |
| | $ | 338 |
| | $ | 363 |
| | $ | 31 |
| | $ | 453 |
| | $ | 484 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, 2011 |
| | Maintenance Capital Expenditures | | Expansion Capital Expenditures | | Total Consolidated Capital Expenditures |
| | (Millions) |
| Our portion | $ | 18 |
| | $ | 304 |
| | $ | 322 |
|
| Noncontrolling interest portion and reimbursable projects (a) | 6 |
| | 57 |
| | 63 |
|
| Total | $ | 24 |
| | $ | 361 |
| | $ | 385 |
|
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| (a) | In conjunction with our acquisitions of our East Texas and Southeast Texas systems, we entered into agreements with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse us for certain expenditures on capital projects. These reimbursements are for certain capital projects which have commenced within three years from the respective acquisition dates. |
In addition, we invested cash in unconsolidated affiliates of $242 million, $158 million and $8 million net of returns, during the year ended December 31, 2013, 2012 and 2011 respectively, to fund our share of capital expansion projects.
We intend to make cash distributions to our unitholders and our general partner. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, which will include debt and common unit issuances, to fund our acquisition and expansion capital expenditures.
We expect to fund future capital expenditures with funds generated from our operations, borrowings under our Credit Agreement, the issuance of additional partnership units and the issuance of Commercial Paper and long-term debt. If these sources are not sufficient, we will reduce our discretionary spending.
Cash Distributions to Unitholders — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all Available Cash, as defined in the partnership agreement. We made cash distributions to our unitholders and general partner of $277 million, $181 million and $132 million during the years ended December 31, 2013, 2012 and 2011, respectively. We intend to continue making quarterly distribution payments to our unitholders and general partner to the extent we have sufficient cash from operations after the establishment of reserves.
Description of the Credit Agreement — The Credit Agreement consists of a $1 billion revolving credit facility that matures November 10, 2016. As of December 31, 2013, there was no outstanding balance on the revolving credit facility resulting in unused revolver capacity of $664 million, all of which was available for general working capital purposes.
Our obligations under the revolving credit facility are unsecured. The unused portion of the revolving credit facility may be used for letters of credit up to a maximum of $500 million of outstanding letters of credit. At December 31, 2013 and December 31, 2012, we had $1 million outstanding letters of credit issued under the Credit Agreement. Amounts undrawn under the revolving credit facility are available to repay amounts borrowed under our Commercial Paper Program, if necessary.
We may prepay all loans at any time without penalty, subject to the reimbursement of lender breakage costs in the case of prepayment of London Interbank Offered Rate, or LIBOR, borrowings. Indebtedness under the Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.25% based on our current credit rating; or (2) (a) the base rate which shall be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1%, plus (b) an applicable margin of 0.25% based on our current credit rating. The revolving credit facility incurs an annual facility fee of 0.25% based on our current credit rating. This fee is paid on drawn and undrawn portions of the revolving credit facility.
The Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Credit Agreement) of not more than 5.0 to 1.0, and on a temporary basis for not more than three consecutive quarters (including the quarter in which such acquisition is consummated) following the consummation of asset acquisitions in the midstream energy business of not more than 5.5 to 1.0.
Description of Commercial Paper Program – In October 2013, we entered into a Commercial Paper Program under which we may issue unsecured commercial paper notes, or the Notes. The Commercial Paper Program serves as an alternative source of funding and does not increase our current overall borrowing capacity. Amounts available under the Commercial Paper Program may be borrowed, repaid, and re-borrowed from time to time with the maximum aggregate principal amount of Notes outstanding, combined with the amount outstanding under our revolving credit facility, not to exceed $1 billion in the aggregate. Amounts undrawn under our revolving credit facility are available to repay the Notes, if necessary. The maturities of the Notes will vary, but may not exceed 397 days from the date of issue. The Notes will be sold under customary terms in the commercial paper market and may be issued at a discount from par, or, alternatively, may be sold at par and bear varying interest rates on a fixed or floating basis. The proceeds of the issuances of the Notes are expected to be used for capital expenditures and other general partnership purposes. As of December 31, 2013, we had $335 million of commercial paper outstanding which is included in short-term borrowings in our consolidated balance sheets.
The weighted-average interest rate on our commercial paper was 1.14% per annum, excluding the impact of interest rate swaps.
Description of Debt Securities – On March 14, 2013, we issued $500 million of 3.875% 10-year Senior Notes due March 15, 2023. We received proceeds of $490 million, net of underwriters’ fees, related expenses and unamortized discounts totaling $10 million, which we used to fund the cash portion of the purchase price for the acquisition of an additional 46.67% interest in the Eagle Ford system. Interest on the notes will be paid semi-annually on March 15 and September 15 of each year, commencing September 15, 2013. The notes will mature on March 15, 2023, unless redeemed prior to maturity. The underwriters’ fees and related expenses are deferred in other long-term assets in our consolidated balance sheets and will be amortized over the term of the notes.
On November 27, 2012, we issued $500 million of our 2.50% 5-year Senior Notes due December 1, 2017. We received net proceeds of $494 million, net of underwriters’ fees, related expenses and unamortized discounts totaling $6 million, which were used to repay our then-outstanding term loans. Interest on the notes will be paid semi-annually on June 1 and December 1 of each year, commencing June 1, 2013. The notes will mature on December 1, 2017, unless redeemed prior to maturity. The underwriters’ fees and related expenses are deferred in other long-term assets in our consolidated balance sheets and will be amortized over the term of the notes.
On March 13, 2012, we issued $350 million of our 4.95% 10-year Senior Notes due April 1, 2022. We received net proceeds of $346 million, net of underwriters’ fees, related expenses and unamortized discounts totaling $4 million, which we used to fund the cash portion of the acquisition of the remaining 66.67% interest in Southeast Texas and to repay funds borrowed under our Term Loan and Credit Agreement. Interest on the notes is paid semi-annually on April 1 and October 1 of each year. The notes will mature on April 1, 2022, unless redeemed prior to maturity. The underwriters’ fees and related expenses are deferred in other long-term assets in our consolidated balance sheets and will be amortized over the term of the notes.
On September 30, 2010, we issued $250 million of our 3.25% Senior Notes due October 1, 2015. We received net proceeds of $248 million, net of underwriters’ fees, related expense and unamortized discounts of $2 million, which we used to repay funds borrowed under the revolver portion of our Credit Agreement. Interest on the notes is paid semi-annually on April 1 and October 1 of each year. The notes will mature on October 1, 2015, unless redeemed prior to maturity. The underwriters’ fees and related expense are deferred in other long-term assets in our consolidated balance sheets and will be amortized over the term of the notes.
The series of notes are senior unsecured obligations, ranking equally in right of payment with our existing unsecured indebtedness, including indebtedness under our Credit Facility. We are not required to make mandatory redemption or sinking
fund payments with respect to any of these notes, and they are redeemable at a premium at our option.
Total Contractual Cash Obligations and Off-Balance Sheet Obligations
A summary of our total contractual cash obligations as of December 31, 2013, is as follows:
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| | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period |
| | Total | | Less than 1 year | | 1-3 years | | 3-5 years | | Thereafter |
| | (Millions) |
| Debt (a) | $ | 2,333 |
| | $ | 392 |
| | $ | 357 |
| | $ | 586 |
| | $ | 998 |
|
| Operating lease obligations (b) | 94 |
| | 16 |
| | 26 |
| | 19 |
| | 33 |
|
| Purchase obligations (c) | 280 |
| | 199 |
| | 59 |
| | 19 |
| | 3 |
|
| Other long-term liabilities (d) | 27 |
| | — |
| | 3 |
| | — |
| | 24 |
|
| Total | $ | 2,734 |
| | $ | 607 |
| | $ | 445 |
| | $ | 624 |
| | $ | 1,058 |
|
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| (a) | Includes interest payments on debt securities that have been issued. These interest payments are $57 million, $107 million, $86 million, and $148 million for less than one year, one to three years, three to five years, and thereafter, respectively. The above table does not include estimated payments associated with our interest rate swaps as the repayment date and/or future interest rate are indeterminable. |
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| (b) | Our operating lease obligations are contractual obligations, and primarily consist of our leased marine propane terminal and railcar leases, both of which provide supply and storage infrastructure for our Wholesale Propane Logistics business. Operating lease obligations also include natural gas storage in our Northern Louisiana system. The natural gas storage arrangement enables us to maximize the value between the current price of natural gas and the futures market price of natural gas. |
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| (c) | Our purchase obligations are contractual obligations and include purchase orders for capital expenditures, various non-cancelable commitments to purchase physical quantities of propane supply for our Wholesale Propane Logistics business and other items. For contracts where the price paid is based on an index, the amount is based on the forward market prices as of December 31, 2013. Purchase obligations exclude accounts payable, accrued interest payable and other current liabilities recognized in the consolidated balance sheets. Purchase obligations also exclude current and long-term unrealized losses on derivative instruments included in the consolidated balance sheet, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity. In addition, many of our gas purchase contracts include short and long-term commitments to purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from the table. |
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| (d) | Other long-term liabilities include $24 million of asset retirement obligations, $1 million of environmental reserves and $2 million of firm transportation commitments recognized in the December 31, 2013 consolidated balance sheet. In addition, $11 million of deferred state income taxes was excluded as cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year. |
We have no items that are classified as off balance sheet obligations.
Critical Accounting Policies and Estimates
Our financial statements reflect the selection and application of accounting policies that require management to make estimates and assumptions. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations. These accounting policies are described further in Note 2 of the Notes to Consolidated Financial Statements in Exhibit 99.3 to this Form 8-K.
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| | | | |
| Description | | Judgments and Uncertainties | | Effect if Actual Results Differ from Assumptions |
| | | | | |
| Inventories |
| Inventories, which consist of NGLs and natural gas, are recorded at the lower of weighted-average cost or market value. | | Judgment is required in determining the market value of inventory, as the geographic location impacts market prices, and quoted market prices may not be available for the particular location of our inventory. | | If the market value of our inventory is lower than the cost, we may be exposed to losses that could be material. If commodity prices were to decrease by 10% below our December 31, 2013 weighted-average cost, our net income would be affected by approximately $7 million. |
| | | | | |
| Impairment of Goodwill |
| We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. | | We determine fair value using widely accepted valuation techniques, namely discounted cash flow and market multiple analyses. These techniques are also used when assigning the purchase price to acquired assets and liabilities. These types of analyses require us to make assumptions and estimates regarding industry and economic factors and the profitability of future business strategies. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations. | | We primarily use a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. If our assumptions are not appropriate, or future events indicate that our goodwill is impaired, our net income would be impacted by the amount by which the carrying value exceeds the fair value of the reporting unit, to the extent of the balance of goodwill. We have not recorded any impairment charges on goodwill during the year ended December 31, 2013. |
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| Description | | Judgments and Uncertainties | | Effect if Actual Results Differ from Assumptions |
| | | | | |
| Impairment of Long-Lived Assets |
| We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections expected to be realized over the remaining useful life of the primary asset. The carrying amount is not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. | | Our impairment analyses require management to apply judgment in estimating future cash flows as well as asset fair values, including forecasting useful lives of the assets, assessing the probability of different outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. If the carrying value is not recoverable, we assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. These techniques are also used when assigning the purchase price to acquired assets and liabilities. | | Using the impairment review methodology described herein, we have not recorded any impairment charges on long-lived assets during the year ended December 31, 2013. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge. |
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| Impairment of Investments in Unconsolidated Affiliates |
| We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced a decline in value. When evidence of loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. | | Our impairment analyses require management to apply judgment in estimating future cash flows and asset fair values, including forecasting useful lives of the assets, assessing the probability of differing estimated outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. When there is evidence of loss in value, we assess the fair value of our unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. | | Using the impairment review methodology described herein, we have not recorded any impairment charges on investments in unconsolidated affiliates during the year ended December 31, 2013. If the estimated fair value of our unconsolidated affiliates is less than the carrying value, we would recognize an impairment loss for the excess of the carrying value over the estimated fair value. |
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| Description | | Judgments and Uncertainties | | Effect if Actual Results Differ from Assumptions |
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| Accounting for Risk Management Activities and Financial Instruments |
Each derivative not qualifying for the normal purchases and normal sales exception is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on derivative instruments. Derivative assets and liabilities remain classified in our consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments at fair value until the contractual settlement period impacts earnings. Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. | | When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical information and the expected relationship with quoted market prices. | | If our estimates of fair value are inaccurate, we may be exposed to losses or gains that could be material. A 10% difference in our estimated fair value of derivatives at December 31, 2013 would have affected net income by approximately $14 million based on our net derivative position for the year ended December 31, 2013. |
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| Accounting for Asset Retirement Obligations |
| Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit adjusted risk free interest rate, and accretes due to the passage of time based on the time value of money until the obligation is settled. | | Estimating the fair value of asset retirement obligations requires management to apply judgment to evaluate the necessary retirement activities, estimate the costs to perform those activities, including the timing and duration of potential future retirement activities, and estimate the risk free interest rate. When making these assumptions, we consider a number of factors, including historical retirement costs, the location and complexity of the asset and general economic conditions. | | If actual results are not consistent with our assumptions and judgments or our assumptions and estimates change due to new information, we may experience material changes in our asset retirement obligations. Establishing an asset retirement obligation has no initial impact on net income. A 10% change in depreciation and accretion expense associated with our asset retirement obligations during the year ended December 31, 2013 would have less than a $1 million impact on our net income. |
