Attached files
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. We refer to the assets, liabilities and operations of DCP Southeast Texas Holdings, GP, or Southeast Texas, prior to our acquisition of a 33.33% interest from DCP Midstream, LLC in January 2011, and DCP East Texas Holdings, LLC, or East Texas, prior to our acquisition of an additional 25.1% limited liability company interest from DCP Midstream, LLC in April 2009, 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, Wholesale Propane Logistics and NGL Logistics.
The financial information contained herein includes, for each period presented, our accounts, and the assets, liabilities and operations of our 33.33% interest in Southeast Texas acquired from DCP Midstream, LLC in January 2011 and our additional 25.1% limited liability company interest in East Texas acquired from DCP Midstream, LLC in April 2009, transactions among entities under common control, which we refer to as our “predecessor.” Transfers of net assets between entities under common control 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. Prior to our acquisition of an additional 25.1% limited liability company interest in East Texas from DCP Midstream, LLC in April 2009, we owned a 25% limited liability company interest in East Texas, which we accounted for under the equity method of accounting. Subsequent to this transaction we own a 50.1% limited liability interest in East Texas, and account for East Texas as a consolidated subsidiary. Accordingly, our financial information includes the historical results of our predecessor for all periods presented. 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. Specifically, the terms of the Southeast Texas joint venture agreement provide that distributions and earnings to us for the first seven years related to storage and transportation gross margin will be pursuant to a fee-based arrangement, based on storage capacity and tailgate volumes. Distributions and earnings related to the gathering and processing business, along with reductions for all expenditures, will be pursuant to our and DCP Midstream, LLC’s respective ownership interests in Southeast Texas. These terms of the agreement are not reflected in the historical financial statements.
Crude oil and NGL prices have generally remained at favorable levels, although natural gas prices continue to decline and remain lower than prices in 2008 and 2009. With the exception of certain higher liquids content and emerging gas shale regions where drilling activity remains high, the lower natural gas prices are resulting in significantly reduced drilling activity in areas where the gas has a relatively lower liquid content. Gas production in regions with low liquid content receive less price uplift from the relatively higher crude and NGL prices.
During January and February, we experienced near record cold weather, causing operating challenges at our East Texas and Northern Louisiana plants, creating periods of low NGL recoveries and volume curtailments due to plant shut downs and producer wellhead freeze offs.
From May to November, we had an extended planned outage related to an inspection at our Providence wholesale propane terminal, with lower unit margins resulting from the associated logistics of shifting inventory and sales volumes to our other terminals. Earlier in the year, warmer weather and an early spring tempered propane sales volumes. This was partially offset by the cash payment we received in conjunction with an amendment to an existing propane supply contract.
Improvements in several aspects of the business environment along with opportunities in the market enabled us to continue to execute on our growth objectives in 2010 through a series of acquisitions and capital projects around our existing footprint. In January, we completed an acquisition of our Wattenberg fee-based NGL pipeline and announced a related expansion capital project. In July, we acquired an additional 55% interest in our Black Lake fee-based NGL pipeline bringing our ownership interest in Black Lake to 100%. In July, we also closed on an acquisition which expanded our existing northeastern U.S. wholesale propane logistics business into the mid-Atlantic region through the addition of a marine import terminal and storage facility in the Port of Chesapeake, Virginia. Prior to year-end, we further expanded our NGL logistics business in the Midwest, Sarnia and Northeast supply markets through the acquisition of an NGL storage facility in Marysville, Michigan.
1
On November 4, 2010, we entered into agreements with DCP Midstream, LLC, to acquire a 33.33% interest in Southeast Texas, for $150.0 million. The Southeast Texas system is a fully integrated midstream business which includes 675 miles of natural gas pipelines, three natural gas processing plants with recently increased processing capacity totaling 380 MMcf/d and natural gas storage assets with 9 Bcf of existing storage capacity. The terms of the joint venture agreement provide that distributions to us for the first seven years related to storage and transportation gross margin will be pursuant to a fee-based arrangement, based on storage capacity and tailgate volumes. Distributions related to the gathering and processing business, along with reductions for all expenditures, will be pursuant to our and DCP Midstream, LLC’s respective ownership interests in Southeast Texas. The transaction closed on January 1, 2011.
Through the growth opportunities executed, we increased our business diversity, geographic and resource exposure, and our fee-based margins. Our integration efforts related to the acquisitions are progressing according to plan. The Wattenberg capital expansion project, which we expect to complete in early 2011, is also progressing on plan.
We believe our financial positioning is a key element of our growth strategy and that our accomplishments related to our financial objectives position us well in terms of both liquidity and cost of capital to support our growth plans. In September, we successfully executed our inaugural public debt offering through the issuance of $250.0 million of senior notes due 2015. We raised $189.3 million in capital through the successful execution of two public equity offerings in August and November.
Financial results for the year were in line with our previously provided 2010 forecast. Resuming distribution growth was an important 2010 objective, with the past year serving as a transition year to consistent distribution growth. We raised our distribution in the second and fourth quarters, resulting in a 3% increase in our quarterly distribution rate over the rate paid in the fourth quarter of 2009. The distributions reflect our business results as well as our recent execution on growth opportunities.
General Trends and Outlook
In 2011, 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 distributable cash flows. We believe the key elements to stable distributable cash flows are the diversity of our asset portfolio, our significant fee-based business representing approximately 60% of our estimated margins, and 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 $10.0 and $15.0 million, and expenditures for expansion capital of between $35.0 and $50.0 million in 2011 including $10.0 million for the expansion to storage capacity at our Southeast Texas system. The board of directors may approve additional growth capital during the year at their discretion. This capital does not include any acquisitions or additional investment opportunities that may be identified throughout the course of the year and approved by our management and our board of directors.
In 2011, we expect to continue to pursue a multi-faceted growth strategy, which may include executing on organic opportunities around our footprint, third party acquisitions, and periodic dropdowns from our sponsors in order to grow our distributable cash flows. We also plan to continue to integrate our recent acquisitions and execute on the Wattenberg pipeline expansion project.
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 should natural gas prices and drilling levels continue to experience weakness. Our long-term view is that as economic conditions improve, natural gas prices should return to a level that would support continued natural gas production in the United States. During 2010, petrochemical demand remained strong for NGLs as NGLs were a lower cost feedstock when compared to crude oil derived feedstocks. We anticipate this continuing in 2011.
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 retail propane distribution customers with reliable supplies of propane during peak demand periods of tight supply, usually in the winter months when their retail customers consume the most propane for home heating.
2
Factors That May Significantly Affect Our Results
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 of our processing facilities, (5) potential limitations on throughput volumes arising from downstream and infrastructure capacity constraints, and (6) the terms of our processing contract arrangements with producers.
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 natural gas 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 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.
Wholesale Propane Logistics Segment
Our Wholesale Propane Logistics segment operating results are impacted by our ability to provide our retail 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 inventory value. We generally recover lower of cost or market inventory adjustments in subsequent periods through the sale of inventory. 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 regions of the United States. Our competitors include major integrated oil and gas and energy companies, and interstate and intrastate pipelines.
3
NGL Logistics Segment
Our NGL Logistics segment operating results are impacted by the throughput volumes of the NGLs we transport on our NGL pipelines and the volumes of NGLs we store in our storage facility. We transport 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 commodity prices for ethane. 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. 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 NGLs decline below our carrying value.
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.
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 acquisitions or organic growth projects. 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, volumes or other market declines, including 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
In January 2011, we announced that we are no longer pursuing a joint venture or alternative transaction structures with EQT Corporation.
On January 27, 2011, the board of directors of the general partner declared a quarterly distribution of $0.6175 per unit, payable on February 14, 2011 to unitholders of record on February 7, 2011.
On December 30, 2010, we acquired all of the interests in Marysville Hydrocarbons Holdings, LLC, or Marysville. The acquisition involved three separate transactions with a number of parties. The Partnership acquired a 90% interest in Marysville from Dart Energy Corporation, a 5% interest in Marysville from Prospect Street Energy, LLC and 100% of EE Group, LLC, which owns the remaining 5% interest in Marysville. We paid a purchase price of $94.8 million and $6.0 million for net working capital and other adjustments, for an aggregate purchase price of $100.8 million subject to customary purchase price adjustments, for our 100% interest. The purchase was financed at closing with borrowings under the Partnership’s revolving credit facility. $21.2 million of the purchase price has been deposited in an indemnity escrow to satisfy certain tax liabilities and provide for breaches of representations and warranties of the sellers.
4
On November 4, 2010, we entered into agreements with DCP Midstream, LLC to acquire a 33.33% interest in Southeast Texas for $150.0 million. The Southeast Texas system is a fully integrated midstream business which includes 675 miles of natural gas pipelines, three natural gas processing plants with recently increased processing capacity totaling 380 MMcf/d and natural gas storage assets with 9 Bcf of existing storage capacity. The terms of the joint venture agreement provide that distributions to us for the first seven years related to storage and transportation gross margin will be pursuant to a fee-based arrangement, based on storage capacity and tailgate volumes. Distributions related to the gathering and processing business, along with reductions for all expenditures, will be pursuant to our and DCP Midstream, LLC’s respective ownership interests in Southeast Texas. This acquisition closed on January 1, 2011.
In November 2010, we issued 2,875,000 common units at $34.96 per unit. We received proceeds of $96.2 million, net of offering costs.
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 Wholesale Propane Logistics segment and our NGL 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:
| • | 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 purchase arrangements pursuant to which we purchase 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. |
| • | 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 our returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. 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 less than 6% of our gross margin. Our equity method investment in Discovery, 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 the operating costs. Fluctuations in commodity prices are expected to continue to impact the operating costs of these entities.
5
The natural gas supply for our gathering pipelines and processing plants is derived primarily from natural gas wells located in Colorado, Louisiana, Michigan, Oklahoma, Texas, Wyoming and the Gulf of Mexico. The Pelico system also receives natural gas produced in Texas through its interconnect with other pipelines that transport natural gas from Texas into western Louisiana. These areas have historically experienced significant levels of drilling activity, providing us with opportunities to access newly developed natural gas supplies. We identify primary suppliers as those individually representing 10% or more of our total natural gas supply. Our one primary supplier of natural gas in our Natural Gas Services segment represented approximately 14% of the natural gas supplied to this system in 2010. 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. In 2010, due to the decline in producer drilling in various areas in which we operate, new well connections have been at reduced levels.
We sell natural gas to marketing affiliates of natural gas pipelines, marketing affiliates of integrated oil companies, marketing affiliates of 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, we use a subsidiary of DCP Midstream, LLC as our agent to purchase natural gas from third parties at pipeline interconnect points, as well as residue gas from our Minden and Ada processing plants, 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 may enter into financial derivatives to lock in time spreads and price differentials across the Pelico system to maximize the value of pipeline and storage capacity. We also gather, process and transport natural gas under fee-based transportation contracts. Our Southeast Texas system also manages the value of pipeline and storage capacity in a similar manner, although our 33.33% distributions for the first seven years are fee-based such that we are not exposed to that activity.
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, two of which are affiliated entities, represented approximately 91% of our propane supplied in 2010. We sell propane on a wholesale basis to retail propane distributors who in turn resell propane to their retail customers.
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 retail propane distribution customers with reliable supplies of propane during periods of tight supply, such as the winter months when their retail 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 purchase of propane from us in the summer. We believe these factors generally allow us to maintain our generally favorable relationships with our customers.
We manage our wholesale propane margins by selling propane to retail 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.
NGL Logistics Segment
Our pipelines and storage facility provide transportation 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 or stored and the level of fees charged to customers. We do not take title to the products transported on our NGL pipelines 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 Seabreeze and Wilbreeze pipelines. For the Black Lake pipeline, any line loss or gain in NGLs is allocated to the shipper. 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
6
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 prices reduce the volume of NGLs extracted at plants connected to our NGL pipelines and, in turn, lower the NGL throughput on our assets. In the transportation markets we serve, our pipelines are the sole pipeline facility transporting NGLs from the supply source. Our storage facility in Marysville, Michigan provides storage and related services primarily to depositories operating in the liquid hydrocarbons industry.
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, segment gross margin and adjusted segment gross margin; (3) operating and maintenance expense, and general and administrative expense; (4) adjusted EBITDA; and (5) distributable cash flow. Gross margin, segment gross margin, adjusted segment gross margin, adjusted 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 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 on our pipelines are substantially dependent upon the quantities of NGLs produced at our processing plants, as well as NGLs produced at other processing plants that have pipeline connections with our NGL 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.
Gross Margin, Segment Gross Margin and Adjusted 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 for that segment less commodity purchases for that segment. Our gross margin equals the sum of our segment gross margins. We define adjusted segment gross margin as segment gross margin plus non-cash commodity derivative losses, less non-cash commodity derivative gains for that segment. Gross margin, segment gross margin and adjusted 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, segment gross margin and adjusted segment gross margin 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.
7
Our gross margin, segment gross margin and adjusted segment gross margin 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:
| Reconciliation of Non-GAAP Measures | Year Ended December 31, | |||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
| Reconciliation of net income(loss) attributable to partners to gross margin: |
| |||||||||||
| Net income(loss) attributable to partners |
$ | 62.4 | $ | (10.7 | ) | $ | 153.3 | |||||
| Interest expense |
29.1 | 28.3 | 32.8 | |||||||||
| Income tax expense |
0.3 | 0.6 | 0.6 | |||||||||
| Operating and maintenance expense |
79.8 | 69.7 | 77.4 | |||||||||
| Depreciation and amortization expense |
73.7 | 64.9 | 53.2 | |||||||||
| General and administrative expense |
33.7 | 32.3 | 33.3 | |||||||||
| Other income |
(1.0 | ) | — | (1.5 | ) | |||||||
| Other income — affiliate |
(3.0 | ) | — | — | ||||||||
| Step acquisition — equity interest re-measurement gain |
(9.1 | ) | — | — | ||||||||
| Interest income |
— | (0.3 | ) | (6.1 | ) | |||||||
| Earnings from unconsolidated affiliates |
(38.2 | ) | (26.9 | ) | (29.6 | ) | ||||||
| Net income attributable to noncontrolling interests |
9.2 | 8.3 | 36.1 | |||||||||
| Gross margin |
$ | 236.9 | $ | 166.2 | $ | 349.5 | ||||||
| Non-cash commodity derivative mark-to-market (a) |
$ | (5.4 | ) | $ | (83.4 | ) | $ | 101.6 | ||||
| Reconciliation of segment net income(loss) attributable to partners to segment gross margin: |
||||||||||||
| Natural Gas Services segment: |
||||||||||||
| Segment net income attributable to partners |
$ | 91.7 | $ | 6.3 | $ | 207.1 | ||||||
| Operating and maintenance expense |
63.5 | 58.2 | 66.5 | |||||||||
| Depreciation and amortization expense |
69.1 | 61.9 | 50.5 | |||||||||
| Other income |
(1.0 | ) | — | — | ||||||||
| Earnings from unconsolidated affiliates |
(37.4 | ) | (25.0 | ) | (28.8 | ) | ||||||
| Net income attributable to noncontrolling interests |
9.2 | 8.3 | 36.1 | |||||||||
| Segment gross margin |
$ | 195.1 | $ | 109.7 | $ | 331.4 | ||||||
| Non-cash commodity derivative mark-to-market (a) |
$ | (4.4 | ) | $ | (84.2 | ) | $ | 99.2 | ||||
| Wholesale Propane Logistics segment: |
||||||||||||
| Segment net income attributable to partners |
$ | 17.4 | $ | 37.2 | $ | 1.3 | ||||||
| Operating and maintenance expense |
12.6 | 10.3 | 9.9 | |||||||||
| Depreciation and amortization expense |
1.9 | 1.4 | 1.3 | |||||||||
| Other income |
— | — | (1.5 | ) | ||||||||
| Other income — affiliate |
(3.0 | ) | — | — | ||||||||
| Segment gross margin |
$ | 28.9 | $ | 48.9 | $ | 11.0 | ||||||
| Non-cash commodity derivative mark-to-market (a) |
$ | (1.0 | ) | $ | 0.8 | $ | 2.4 | |||||
| NGL Logistics segment: |
||||||||||||
| Segment net income attributable to partners |
$ | 16.5 | $ | 6.9 | $ | 5.5 | ||||||
| Operating and maintenance expense |
3.7 | 1.2 | 1.0 | |||||||||
| Depreciation and amortization expense |
2.6 | 1.4 | 1.4 | |||||||||
| Step acquisition – equity interest re-measurement gain |
(9.1 | ) | — | — | ||||||||
| Earnings from unconsolidated affiliates |
(0.8 | ) | (1.9 | ) | (0.8 | ) | ||||||
| Segment gross margin |
$ | 12.9 | $ | 7.6 | $ | 7.1 | ||||||
| (a) | Non-cash commodity derivative mark-to-market is included in segment gross margin, along with cash settlements for our derivative contracts. |
8
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, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Affiliate: |
||||||||||||
| Omnibus Agreement |
$ | 9.9 | $ | 9.7 | $ | 9.8 | ||||||
| Other — DCP Midstream, LLC |
9.3 | 10.4 | 10.4 | |||||||||
| Other — affiliate |
0.2 | 0.3 | — | |||||||||
| Total affiliate |
19.4 | 20.4 | 20.2 | |||||||||
| Third Party |
14.3 | 11.9 | 13.1 | |||||||||
| Total |
$ | 33.7 | $ | 32.3 | $ | 33.3 | ||||||
We have entered into an omnibus agreement, as amended, or the Omnibus Agreement, with DCP Midstream, LLC. Under the Omnibus Agreement, 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 Omnibus 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.
On January 1, 2011, we extended the omnibus agreement through December 31, 2011 for $10.2 million. The Omnibus Agreement also addresses the following matters:
| • | DCP Midstream, LLC’s obligation to indemnify us for certain liabilities and our obligation to indemnify DCP Midstream, LLC for certain liabilities; |
| • | DCP Midstream, LLC’s obligation to continue to maintain its credit support for our obligations related to commercial contracts with respect to its business or operations that were in effect at December 7, 2005 until the expiration of such contracts; and |
| • | Our general partner will have the right to agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses, with the concurrence of the special committee of DCP Midstream GP, LLC’s board of directors. |
East Texas incurs general and administrative expenses directly from DCP Midstream, LLC. During the years ended December 31, 2010, 2009 and 2008, East Texas incurred $7.8 million, $8.5 million and $8.6 million, respectively, for general and administrative expenses from DCP Midstream, LLC, which includes expenses for our predecessor operations.
Outside of the Omnibus Agreement and amounts incurred by East Texas, we incurred other fees with DCP Midstream, LLC, which includes expenses for our predecessor operations, of $1.5 million, $1.9 million and $1.8 million, respectively, for the years ended December 31, 2010, 2009 and 2008, respectively. These amounts include allocated expenses, including professional services, insurance and internal audit.
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.
9
Adjusted EBITDA and Distributable Cash Flow — 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. Adjusted EBITDA 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:
| • | 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; |
| • | 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; and |
| • | the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
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.
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 (see “— Liquidity and Capital Resources” for further definition of maintenance capital expenditures). Maintenance capital expenditures are capital expenditures made where we add on to or improve capital assets owned, or acquire or construct new capital assets, if such expenditures are made to maintain, including over the long term, our operating capacity or revenues. 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. 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.
10
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, 2010, 2009 and 2008. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
| Variance 2010 vs. 2009 |
Variance 2009 vs. 2008 |
|||||||||||||||||||||||||||
| Year Ended December 31, | Increase | Increase | ||||||||||||||||||||||||||
| 2010 (a)(b) | 2009 (a)(b) | 2008 (a)(b) | (Decrease) | Percent | (Decrease) | Percent | ||||||||||||||||||||||
| (Millions, except as indicated) | ||||||||||||||||||||||||||||
| Operating revenues: |
||||||||||||||||||||||||||||
| Natural Gas Services (c) |
$ | 778.7 | $ | 583.7 | $ | 1,336.2 | $ | 195.0 | 33 | % | $ | (752.5 | ) | (56 | )% | |||||||||||||
| Wholesale Propane Logistics |
473.2 | 348.2 | 483.0 | 125.0 | 36 | % | (134.8 | ) | (28 | )% | ||||||||||||||||||
| NGL Logistics |
17.6 | 10.5 | 11.3 | 7.1 | 68 | % | (0.8 | ) | (7 | )% | ||||||||||||||||||
| Total operating revenues |
1,269.5 | 942.4 | 1,830.5 | 327.1 | 35 | % | (888.1 | ) | (49 | )% | ||||||||||||||||||
| Gross margin (d): |
||||||||||||||||||||||||||||
| Natural Gas Services |
195.1 | 109.7 | 331.4 | 85.4 | 78 | % | (221.7 | ) | (67 | )% | ||||||||||||||||||
| Wholesale Propane Logistics |
28.9 | 48.9 | 11.0 | (20.0 | ) | (41 | )% | 37.9 | 345 | % | ||||||||||||||||||
| NGL Logistics |
12.9 | 7.6 | 7.1 | 5.3 | 70 | % | 0.5 | 7 | % | |||||||||||||||||||
| Total gross margin |
236.9 | 166.2 | 349.5 | 70.7 | 43 | % | (183.3 | ) | (52 | )% | ||||||||||||||||||
| Operating and maintenance expense |
(79.8 | ) | (69.7 | ) | (77.4 | ) | 10.1 | 14 | % | (7.7 | ) | (10 | )% | |||||||||||||||
| Depreciation and amortization expense |
(73.7 | ) | (64.9 | ) | (53.2 | ) | 8.8 | 14 | % | 11.7 | 22 | % | ||||||||||||||||
| General and administrative expense |
(33.7 | ) | (32.3 | ) | (33.3 | ) | 1.4 | 4 | % | (1.0 | ) | (3 | )% | |||||||||||||||
| Step acquisition — equity interest re-measurement gain |
9.1 | — | — | 9.1 | 100 | % | — | — | % | |||||||||||||||||||
| Other income |
1.0 | — | 1.5 | 1.0 | 100 | % | (1.5 | ) | (100 | )% | ||||||||||||||||||
| Other income — affiliates |
3.0 | — | — | 3.0 | 100 | % | — | — | % | |||||||||||||||||||
| Earnings from unconsolidated affiliates (e) |
38.2 | 26.9 | 29.6 | 11.3 | 42 | % | (2.7 | ) | (9 | )% | ||||||||||||||||||
| Interest income |
— | 0.3 | 6.1 | (0.3 | ) | (100 | )% | (5.8 | ) | (95 | )% | |||||||||||||||||
| Interest expense |
(29.1 | ) | (28.3 | ) | (32.8 | ) | 0.8 | 3 | % | (4.5 | ) | (14 | )% | |||||||||||||||
| Income tax expense |
(0.3 | ) | (0.6 | ) | (0.6 | ) | (0.3 | ) | (50 | )% | — | — | % | |||||||||||||||
| Net income attributable to noncontrolling interests |
(9.2 | ) | (8.3 | ) | (36.1 | ) | 0.9 | 11 | % | (27.8 | ) | (77 | )% | |||||||||||||||
| Net income (loss) attributable to partners |
$ | 62.4 | $ | (10.7 | ) | $ | 153.3 | $ | 73.1 | * | $ | (164.0 | ) | * | ||||||||||||||
| Other data: |
||||||||||||||||||||||||||||
| Non-cash commodity derivative mark-to-market |
$ | (5.4 | ) | $ | (83.4 | ) | $ | 101.6 | $ | 78.0 | 94 | % | $ | (185.0 | ) | * | ||||||||||||
| Natural gas throughput (MMcf/d) (e) |
1,272 | 1,152 | 1,035 | 120 | 10 | % | 117 | 11 | % | |||||||||||||||||||
| NGL gross production (Bbls/d) (e) |
40,962 | 34,708 | 32,946 | 6,254 | 18 | % | 1,762 | 5 | % | |||||||||||||||||||
| Propane sales volume (Bbls/d) |
22,350 | 22,278 | 21,053 | 72 | — | % | 1,225 | 6 | % | |||||||||||||||||||
| NGL pipelines throughput (Bbls/d) (e) |
38,282 | 30,160 | 31,407 | 8,122 | 27 | % | (1,247 | ) | (4 | )% | ||||||||||||||||||
| * | Percentage change is not meaningful. |
| (a) | Includes the results of certain companies that held natural gas gathering and treating assets purchased from MichCon Pipeline Company since November 24, 2009, the date of acquisition, and the results of Michigan Pipeline & Processing, LLC, or MPP, since October 1, 2008, the date of acquisition, in our Natural Gas Services Segment. |
Includes the results of Atlantic Energy, since July 30, 2010, the date of acquisition, in our Wholesale Propane Logistics segment.
Includes the results of our Wattenberg pipeline acquired from Buckeye Partners, L.P, since January 28, 2010, the date of acquisition, and an additional 50% interest in Black Lake acquired from an affiliate of BP PLC, since July 30, 2010, the date of acquisition, in our NGL Logistics segment. The acquisition of an additional 50% interest in Black Lake brought our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.
The impact to our results related to Marysville, acquired on December 30, 2010, is not significant.
11
| (b) | We utilize commodity derivative instruments to provide stability to distributable cash flows for our proportionate ownership in East Texas as well as all other natural gas services assets. We do not utilize commodity derivative instruments for the proportionate interest in East Texas that is owned by DCP Midstream, LLC. As such, the portion of East Texas owned by DCP Midstream, LLC is unhedged. Our consolidated results depict 75% of East Texas unhedged in all periods prior to the second quarter of 2009 and 49.9% of East Texas unhedged for all periods subsequent to the first quarter of 2009. |
| (c) | Includes the effect of the acquisition of the NGL Hedge, contributed by DCP Midstream, LLC, in April 2009. The NGL Hedge was a fixed price natural gas liquids derivative by NGL component, which commenced in April 2009 and expired in March 2010. The NGL Hedge was for a total of 1.9 million barrels at $66.72 per barrel. |
| (d) | Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs, and segment gross margin for each segment consists of total operating revenues for that segment, less commodity purchases for that segment. Please read “How We Evaluate Our Operations” above. |
| (e) | Includes our proportionate share of the throughput volumes and NGL production of Collbran, Jackson Pipeline Company, or Jackson, East Texas, Discovery and Southeast Texas and our proportionate earnings of Discovery and Southeast Texas. Earnings for Discovery include the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment. |
For periods prior to July 30, 2010, includes our 50% share of the throughput volumes and earnings for Black Lake. Black Lake’s earnings included the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.
Year Ended December 31, 2010 vs. Year Ended December 31, 2009
Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:
| • | $126.6 million increase primarily attributable to higher propane prices and our acquisition of Atlantic Energy in July 2010, which impact both sales and purchases, partially offset by a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather; |
| • | $122.7 million increase primarily attributable to higher commodity prices, which impact both sales and purchases, and an increase in NGL production, partially offset by changes in contract mix, increased fuel consumption, differences in gas quality, the impact of volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter, as well as a decrease in natural gas sales volumes across certain assets. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project; |
| • | $57.3 million increase related to commodity derivative activity. This increase includes a decrease in unrealized losses of $77.5 million due to movements in forward prices of commodities, partially offset by a decrease in realized cash settlement gains of $20.2 million due to generally higher average prices of commodities in 2010; and |
| • | $20.1 million increase in transportation, processing and other revenue, which represents our fee-based revenues, primarily as a result of increased throughput volumes due to our Michigan and Wattenberg acquisitions, our acquisition of an additional 50% interest in Black Lake, our organic growth project in the Piceance Basin, as well as the renegotiation of commodity sensitive contracts to fee-based contracts. |
Gross Margin — Gross margin increased in 2010 compared to 2009, primarily as a result of the following:
| • | $85.4 million increase for our Natural Gas Services segment, primarily related to commodity derivative activity as explained in the operating revenue section above, higher commodity prices, increased fee-based throughput volumes resulting from the Michigan acquisition, our organic growth project in the Piceance Basin and the renegotiation of commodity sensitive contracts to fee-based contracts, partially offset by reduced natural gas basis spreads, increased fuel consumption, decreased natural gas volumes and differences in gas quality across certain of our assets, as well as the impact of volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and operational downtime; and |
12
| • | $5.3 million increase for our NGL Logistics segment as a result of higher volumes from our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake. |
These increases were partially offset by:
| • | $20.0 million decrease for our Wholesale Propane Logistics segment. 2010 results reflect a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather. 2009 results reflect increased spot sales volumes and significantly higher per unit margins, approximately $6.0 million of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008. |
Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009 primarily as a result of our Michigan acquisition and integration costs, turnaround activities at certain assets, our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.
Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of our capital projects completed in 2009, our Michigan acquisition, our Atlantic Energy acquisition, our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.
Step acquisition — equity interest re-measurement gain — Step acquisition — equity interest re-measurement gain results from our acquisition of an additional 50% interest in Black Lake, bringing our ownership interest in Black Lake to 100% in our NGL Logistics segment. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we remeasured our initial 50% equity interest in Black Lake to its fair value, and recognized a gain of $9.1 million.
Other income — affiliates — Other income — affiliates increased due to a $3.0 million payment received in the second quarter of 2010 from Spectra Energy, a supplier for our Wholesale Propane Logistics segment, related to an amendment of a supply agreement to shorten the term of the agreement by two years.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2010 compared to 2009, primarily as a result of increased earnings from Discovery and Southeast Texas. The 2010 results for Southeast Texas include the impact of Hurricane Ike business interruption insurance recoveries. Settlements related to our commodity derivatives on Discovery are included in segment gross margin.
Net income attributable to noncontrolling interests — Net income attributable to noncontrolling interests includes the impact of organic growth from our Piceance Basin expansion project, offset by volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather in the first quarter, increased fuel consumption and differences in gas quality at East Texas in 2010. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas.
Year Ended December 31, 2009 vs. Year Ended December 31, 2008
Total Operating Revenues — Total operating revenues decreased in 2009 compared to 2008, primarily due to the following:
| • | $622.2 million decrease primarily attributable to decreased commodity prices, which impact both sales and purchases, and a decrease in natural gas sales volumes across certain assets. 2009 results include the impact of a third party owned pipeline rupture, resulting in a fire at East Texas. Results in both years were impacted by hurricanes and operational downtime for our Natural Gas Services segment; |
| • | $137.5 million decrease related to commodity derivative activity. This increase in losses includes an increase in unrealized losses of $184.8 million due to forward prices of commodities increasing in 2009 compared to 2008, partially offset by an increase in realized cash settlement gains of $47.3 million due to generally lower average prices of commodities in 2009; |
| • | $134.9 million decrease primarily attributable to lower propane prices, which impact both sales and purchases, partially offset by increased sales volumes, for our Wholesale Propane Logistics segment; and |
| • | $2.4 million decrease due primarily to lower NGL throughput volumes partially offset by increased per unit margins, for our NGL Logistics segment. |
13
These decreases were partially offset by:
| • | $9.1 million increase in transportation processing and other revenue, which represents our fee-based revenue, primarily attributable to increased throughput volumes due to our Michigan acquisitions, partially offset by decreases in throughput volumes across other assets. |
Gross Margin — Gross margin decreased in 2009 compared to 2008, primarily due to the following:
| • | $221.7 million decrease for our Natural Gas Services segment primarily due to decreases related to commodity derivative activity, lower commodity prices and lower natural gas volumes across certain assets. These decreases include the impact of a third party owned pipeline rupture, resulting in a fire at East Texas in the first quarter of 2009. The decreases were partially offset by increased fee-based throughput volumes due to our Michigan acquisitions. Results in both years were impacted by hurricanes and operational downtime. |
These decreases were partially offset by:
| • | $37.9 million increase for our Wholesale Propane Logistics segment as a result of increased volumes and margins, a portion of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008. |
| • | $0.5 million increase for our NGL Logistics segment, primarily due to higher per-unit margins. |
Operating and Maintenance Expense — Operating and maintenance expense decreased in 2009 compared to 2008, primarily as a result of our cost reduction initiatives, partially offset by increased expenses as a result of the Michigan acquisitions.
Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2009 compared to 2008, primarily as a result of our Michigan acquisitions and our East Texas, Wyoming and Piceance Basin capital projects.
General and Administrative Expense — General and administrative expense decreased in 2009 compared to 2008, primarily as a result of our cost reduction initiatives, partially offset by our Michigan acquisitions.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2009 compared to 2008, primarily due to increased earnings from Black Lake, partially offset by decreased earnings from Discovery and Southeast Texas. Settlements related to our commodity derivatives on Discovery are included in segment gross margin.
Net income attributable to noncontrolling interests — Net income attributable to noncontrolling interests decreased in 2009 primarily due to lower earnings at East Texas, for which the portion owned by DCP Midstream, LLC is unhedged. 2009 results include the impact of a third party owned pipeline rupture, resulting in a fire at East Texas.
14
Results of Operations — Natural Gas Services Segment
This segment consists of our Northern Louisiana system, the Southern Oklahoma system, a 40% limited liability company interest in Discovery, our 33.33% equity interest in the Southeast Texas system, our Colorado and Wyoming systems, our East Texas systems, and our Michigan system.
| Variance 2010 vs. 2009 |
Variance 2009 vs. 2008 |
|||||||||||||||||||||||||||
| Year Ended December 31, | Increase | Increase | ||||||||||||||||||||||||||
| 2010 (a)(b) | 2009 (a)(b) | 2008 (a)(b) | (Decrease) | Percent | (Decrease) | Percent | ||||||||||||||||||||||
| (Millions, except as indicated) | ||||||||||||||||||||||||||||
| Operating revenues: |
||||||||||||||||||||||||||||
| Sales of natural gas, NGLs and condensate |
$ | 684.2 | $ | 562.8 | $ | 1,185.2 | $ | 121.4 | 22 | % | $ | (622.4 | ) | (53 | )% | |||||||||||||
| Transportation, processing and other |
102.1 | 87.3 | 79.1 | 14.8 | 17 | % | 8.2 | 10 | % | |||||||||||||||||||
| (Losses) gains from commodity derivative activity (c) |
(7.6 | ) | (66.4 | ) | 71.9 | 58.8 | 89 | % | (138.3 | ) | * | |||||||||||||||||
| Total operating revenues |
778.7 | 583.7 | 1,336.2 | 195.0 | 33 | % | (752.5 | ) | (56 | )% | ||||||||||||||||||
| Purchases of natural gas and NGLs |
583.6 | 474.0 | 1,004.8 | 109.6 | 23 | % | (530.8 | ) | (53 | )% | ||||||||||||||||||
| Segment gross margin (d) |
195.1 | 109.7 | 331.4 | 85.4 | 78 | % | (221.7 | ) | (67 | )% | ||||||||||||||||||
| Operating and maintenance expense |
(63.5 | ) | (58.2 | ) | (66.5 | ) | 5.3 | 9 | % | (8.3 | ) | (12 | )% | |||||||||||||||
| Depreciation and amortization expense |
(69.1 | ) | (61.9 | ) | (50.5 | ) | 7.2 | 12 | % | 11.4 | 23 | % | ||||||||||||||||
| Other income |
1.0 | — | — | 1.0 | 100 | % | — | — | % | |||||||||||||||||||
| Earnings from unconsolidated affiliates (e) |
37.4 | 25.0 | 28.8 | 12.4 | 50 | % | (3.8 | ) | (13 | )% | ||||||||||||||||||
| Segment net income |
100.9 | 14.6 | 243.2 | 86.3 | 591 | % | (228.6 | ) | (94 | )% | ||||||||||||||||||
| Segment net income attributable to noncontrolling interests |
(9.2 | ) | (8.3 | ) | (36.1 | ) | 0.9 | 11 | % | (27.8 | ) | (77 | )% | |||||||||||||||
| Segment net income attributable to partners |
$ | 91.7 | $ | 6.3 | $ | 207.1 | $ | 85.4 | 1,355 | $ | (200.8 | ) | (97 | )% | ||||||||||||||
| Other data: |
||||||||||||||||||||||||||||
| Natural gas throughput (MMcf/d) (e) |
1,272 | 1,152 | 1,035 | 120 | 10 | % | 117 | 11 | % | |||||||||||||||||||
| NGL gross production (Bbls/d) (e) |
40,962 | 34,708 | 32,946 | 6,254 | 18 | % | 1,762 | 5 | % | |||||||||||||||||||
| * | Percentage change is not meaningful. |
| (a) | Includes the results of certain companies that held natural gas gathering and treating assets purchased from MichCon Pipeline Company since November 24, 2009, the date of acquisition, and the results of MPP since October 1, 2008, the date of acquisition. |
| (b) | We utilize commodity derivative instruments to provide stability to distributable cash flows for our ownership in East Texas as well as all other natural gas services assets, the portion of East Texas owned by DCP Midstream, LLC is unhedged. As such, our consolidated results depict 75% of East Texas unhedged in all periods prior to the second quarter of 2009 and 49.9% of East Texas unhedged for all periods subsequent to the first quarter of 2009. |
| (c) | Includes the effect of the acquisition of the NGL Hedge, contributed by DCP Midstream, LLC in April 2009. The NGL Hedge is a fixed price natural gas liquids derivative by NGL component, which commenced in April 2009 and expired in March 2010. |
| (d) | Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas and NGLs. Please read “How We Evaluate Our Operations” above. |
| (e) | Includes our proportionate share of the throughput volumes and NGL production of Collbran, Jackson, East Texas, Discovery and Southeast Texas and our proportionate share of the earnings of Discovery and Southeast Texas for each period presented. Earnings for Discovery include the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment. |
15
Year Ended December 31, 2010 vs. Year Ended December 31, 2009
Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:
| • | $144.5 million increase attributable to increased commodity prices, which impact both sales and purchases; |
| • | $58.8 million increase related to commodity derivative activity. This increase includes a decrease in unrealized losses of $79.4 million due to movements in forward prices of commodities, partially offset by a decrease in realized cash settlement gains of $20.6 million due to generally higher average prices of commodities in 2010; |
| • | $30.0 million increase as a result of increased NGL production and a change to a contract with an affiliate in the Piceance Basin, such that certain revenues changed from a net presentation in transportation, processing and other to a gross presentation in sales of natural gas, NGLs and condensate; and |
| • | $14.8 million increase primarily as a result of increased fee-based throughput volumes resulting from the Michigan acquisition, our organic growth project in the Piceance Basin, as well as the renegotiation of commodity sensitive contracts to fee-based contracts partially offset by decreases across certain assets. |
These increases were partially offset by:
| • | $53.5 million decrease due primarily to the impact of changes in contract mix, increased fuel consumption, differences in gas quality, a decrease in natural gas sales volume across certain of assets, as well as volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas, and our Wyoming pipeline integrity and system enhancement project. |
Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs increased in 2010 compared to 2009, primarily as a result of increased commodity prices, which impact both sales and purchases, as well as a change to a contract with an affiliate in the Piceance Basin, such that certain purchases changed from a net presentation in transportation, processing and other to a gross presentation in purchases of natural gas and NGLs.
Segment Gross Margin — Segment gross margin increased in 2010 compared to 2009, primarily as a result of the following:
| • | $58.8 million increase related to commodity derivative activities as discussed in the Operating Revenues section above; |
| • | $31.2 million increase as a result of higher commodity prices; and |
| • | $14.8 million increase as a result of increased fee-based throughput volumes resulting from the Michigan acquisition, our organic growth project in the Piceance Basin, as well as the renegotiation of commodity sensitive contracts to fee-based contracts partially offset by decreases across certain assets. |
These increases were partially offset by:
| • | $19.4 million decrease attributable to reduced natural gas basis spreads, increased fuel consumption, the impact of changes in contract mix, differences in gas quality, the impact of volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter and other natural gas volume reductions across certain of our assets. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project. |
Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009 primarily as a result of our Michigan acquisition and integration costs, turnaround activities at certain assets, repairs as a result of near record cold weather and efficiency projects.
Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009 primarily as a result of our capital projects completed in 2009 and the Michigan acquisition.
Other income — Other income relates to our reassessment of the fair value of contingent consideration for our acquisition of an additional 5% interest in Collbran from Delta Petroleum Company, or Delta, in February 2010.
16
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, primarily representing our 40% ownership of Discovery and our 33.33% ownership of Southeast Texas, increased in 2010 compared to 2009 primarily due to higher prices and increased NGL production. The 2010 results for Southeast Texas include Hurricane Ike business interruption insurance recoveries. Earnings from Discovery were partially offset by differences in gas quality, higher costs and downtime related to turnarounds. Settlements related to our commodity derivatives on Discovery are included in segment gross margin.
Segment net income attributable to noncontrolling interests — Segment net income attributable to noncontrolling interests includes the impact of organic growth from our Piceance Basin expansion project, offset by volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather in the first quarter, increased fuel consumption, differences in gas quality and turnarounds at East Texas in 2010. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas.
Natural Gas Throughput — Natural gas transported, processed and/or treated increased in 2010 compared to 2009, as a result of increased fee-based throughput volumes from our Michigan acquisition, and increased volumes at Discovery, partially offset by decreased volumes across certain assets. 2010 results include the impact of volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter. 2009 results include the first quarter impact of operational downtime following the hurricanes, a third party owned pipeline rupture resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.
NGL Gross Production — NGL production increased in 2010 compared to 2009, due primarily to increased volumes from our Piceance Basin expansion project and increased NGL production at Discovery. 2010 results include the impact of volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter. 2009 results include the first quarter impact of operational downtime following the hurricanes, a third party owned pipeline rupture resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.
Year Ended December 31, 2009 vs. Year Ended December 31, 2008
Total Operating Revenues — Total operating revenues decreased in 2009 compared to 2008, primarily due to the following:
| • | $560.1 million decrease attributable to decreased commodity prices, which impact both sales and purchases, and includes the results of East Texas for which the portion owned by DCP Midstream, LLC is unhedged; |
| • | $138.3 million decrease related to commodity derivative activity. This increase in losses includes an increase in unrealized losses of $183.2 million due to forward prices of commodities increasing in 2009 compared to 2008, partially offset by an increase in realized cash settlement gains of $44.9 million due to generally lower average prices of commodities in 2009; and |
| • | $62.1 million decrease due primarily to a decrease in natural gas sales volumes across certain assets, partially offset by increased revenues due to contractual amendments such that certain revenues changed from a net presentation to a gross presentation. These results include the impact of a third party owned pipeline rupture, resulting in a fire at East Texas in the first quarter of 2009. Results in both years include the impact of hurricanes and our Wyoming pipeline integrity and system enhancement project. |
These decreases were partially offset by:
| • | $8.2 million increase in transportation, processing and other revenue, which represents our fee-based revenues, primarily as a result of increased throughput volumes due to the Michigan acquisitions, partially offset by decreased throughput volumes across other assets. |
Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs decreased in 2009 compared to 2008, primarily due to decreased commodity prices, which impact both sales and purchases, partially offset by contractual amendments which resulted in a prospective change in certain purchases from a net presentation to a gross presentation.
Segment Gross Margin — Segment gross margin decreased in 2009 compared to 2008, primarily as a result of the following:
| • | $138.3 million decrease related to commodity derivative activity, as discussed in the Operating Revenues section above; |
| • | $78.8 million decrease due to lower commodity prices, which includes the results of East Texas for which the portion owned by DCP Midstream, LLC is unhedged; and |
17
| • | $21.1 million decrease, primarily due to lower natural gas volumes across certain assets. These decreases include the impact of a third party owned pipeline rupture, resulting in a fire at East Texas in the first quarter of 2009. Results in both years include the impact of hurricanes and our Wyoming pipeline integrity and system enhancement project. |
These decreases were partially offset by:
| • | $16.7 million increase primarily as a result of increased fee-based throughput volumes due to the Michigan acquisitions. |
Operating and Maintenance Expense — Operating and maintenance expense decreased in 2009 compared to 2008, primarily as a result of our cost reduction initiatives, partially offset by increased expenses as a result of our Michigan acquisitions.
Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2009 compared to 2008, primarily as a result of the Michigan acquisitions, and our East Texas, Wyoming and Piceance Basin capital projects.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates related to our 40% ownership of Discovery decreased in 2009 compared to 2008. This decrease was as a result of a reduction in the recognition of Discovery’s deficit purchase price in 2009 compared to 2008. The reduction of deficit purchase price recognition was partially offset by increased earnings from Discovery. The increase in Discovery’s earnings are primarily as a result of the following variances in earnings drivers, representing 100% of Discovery’s results of operations: net income increased $2.5 million, or 7%, due primarily to $12.4 million higher gathering and transportation revenue, $13.2 million lower operating and maintenance expense and $2.6 million lower depreciation and accretion expense. These increases were largely offset by $18.5 million lower NGL sales margins resulting from sharply lower average per-unit margins on higher volumes of NGL equity sales and a $5.4 million unfavorable change in other income or expense, net. Earnings from unconsolidated affiliates related to our 33.33% ownership of Southeast Texas decreased in 2009 compared to 2008. This decrease was a result of lower commodity prices, partially offset by increased natural gas throughput and NGL production volumes. Settlements related to our commodity derivatives on Discovery are included in segment gross margin.
Segment net income attributable to noncontrolling interests — Segment net income attributable to noncontrolling interests decreased in 2009 compared to 2008 primarily as a result of decreased net income at East Texas, for which the portion owned by DCP Midstream, LLC is unhedged. 2009 results include the impact of a third party owned pipeline rupture resulting in a fire at East Texas.
Natural Gas Throughput — Natural gas transported, processed and/or treated increased in 2009 compared to 2008, due to increased fee-based throughput volumes from our Michigan acquisitions and increased volumes from the Tahiti project at Discovery, partially offset by decreased volumes across certain assets. Results in both years include the impact of hurricanes and operational downtime following the hurricanes. 2009 results include the impact of a third party owned pipeline rupture resulting in a fire at East Texas during the first quarter.
NGL Gross Production — NGL production increased in 2009 compared to 2008, due primarily to increased NGL production from Discovery. Results in both periods include the impact of hurricanes and operational downtime and our Wyoming system pipeline integrity and enhancement project. 2009 results also include the impact of a third party owned pipeline rupture, resulting in a fire at East Texas during the first quarter.
18
Results of Operations — Wholesale Propane Logistics Segment
This segment includes our propane transportation facilities, which includes one owned underground storage facility, six owned 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 2010 vs. 2009 |
Variance 2009 vs. 2008 |
||||||||||||||||||||||||||
| 2010 (a) | 2009 | 2008 | Increase (Decrease) |
Percent | Increase (Decrease) |
Percent | ||||||||||||||||||||||
| (Millions, except operating data) | ||||||||||||||||||||||||||||
| Operating revenues: |
||||||||||||||||||||||||||||
| Sales of propane |
$ | 473.8 | $ | 347.2 | $ | 482.1 | $ | 126.6 | 36 | % | $ | (134.9 | ) | (28 | )% | |||||||||||||
| Transportation, processing and other |
0.3 | 0.4 | 1.1 | (0.1 | ) | (25 | )% | (0.7 | ) | (64 | )% | |||||||||||||||||
| (Losses) gains from commodity derivative activity |
(0.9 | ) | 0.6 | (0.2 | ) | (1.5 | ) | * | 0.8 | * | ||||||||||||||||||
| Total operating revenues |
473.2 | 348.2 | 483.0 | 125.0 | 36 | % | (134.8 | ) | (28 | )% | ||||||||||||||||||
| Purchases of propane |
444.3 | 299.3 | 472.0 | 145.0 | 48 | % | (172.7 | ) | (37 | )% | ||||||||||||||||||
| Segment gross margin (b) |
28.9 | 48.9 | 11.0 | (20.0 | ) | (41 | )% | 37.9 | 345 | % | ||||||||||||||||||
| Operating and maintenance expense |
(12.6 | ) | (10.3 | ) | (9.9 | ) | 2.3 | 22 | % | 0.4 | 4 | % | ||||||||||||||||
| Depreciation and amortization expense |
(1.9 | ) | (1.4 | ) | (1.3 | ) | 0.5 | 36 | % | 0.1 | 8 | % | ||||||||||||||||
| Other income – affiliates |
3.0 | — | 1.5 | 3.0 | 100 | % | (1.5 | ) | (100 | )% | ||||||||||||||||||
| Segment net income attributable to partners |
$ | 17.4 | $ | 37.2 | $ | 1.3 | $ | (19.8 | ) | (53 | )% | $ | 35.9 | 2,762 | % | |||||||||||||
| Operating Data: |
||||||||||||||||||||||||||||
| Propane sales volume (Bbls/d) |
22,350 | 22,278 | 21,053 | 72 | — | % | 1,225 | 6 | % | |||||||||||||||||||
| * | Percentage change is not meaningful. |
| (a) | Includes the results of Atlantic Energy, since July 30, 2010, the date of acquisition. |
| (b) | Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of propane. Please read “How We Evaluate Our Operations” above. |
Year Ended December 31, 2010 vs. Year Ended December 31, 2009
Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:
| • | $111.7 million increase attributable to higher propane prices, which impact both sales and purchases; and |
| • | $35.4 million increase attributable to our acquisition of Atlantic Energy in July 2010. |
This increase was partially offset by:
| • | $20.5 million decrease attributable to a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather; |
| • | $1.5 million decrease due to commodity derivative activity. |
Purchases of Propane — Purchases of propane increased in 2010 compared to 2009 as a result of higher propane prices, which impact both sales and purchases, and our acquisition of Atlantic Energy in July 2010, partially offset by decreased propane sales volumes.
Segment Gross Margin — Segment gross margin decreased in 2010 compared to 2009. 2010 results reflect a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather, partially offset by our acquisition of Atlantic Energy in July 2010. 2009 results reflect a late winter, increased spot sales volumes and significantly higher per unit margins, approximately $6.0 million of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008.
19
Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of our acquisition of Atlantic Energy.
Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of our acquisition of Atlantic Energy.
Other income — affiliates — Other income — affiliates increased due to a $3.0 million payment received in the second quarter of 2010 from Spectra Energy, related to an amendment of a supply agreement to shorten the term of the agreement by two years.
Propane Sales Volume — Propane sales volumes were stable in 2010 compared to 2009. 2010 results reflect increased volumes due to our acquisition of Atlantic Energy, offset by a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather. 2009 results reflect a late winter and increased spot sales volume.
Year Ended December 31, 2009 vs. Year Ended December 31, 2008
Total Operating Revenues — Total operating revenues decreased in 2009 compared to 2008, primarily due to the following:
| • | $163.8 million decrease attributable to lower propane prices, which impact both sales and purchases. |
This decrease was partially offset by:
| • | $28.9 million increase attributable to increased propane sales volumes; and |
| • | $0.8 million increase related to commodity derivative activity. |
Purchases of Propane — Purchases of propane decreased in 2009 compared to 2008, due to lower propane prices, which impact both sales and purchases, partially offset by increased volumes.
Segment Gross Margin — Segment gross margin increased in 2009 compared to 2008, primarily as a result of increased volumes and per unit margins, approximately $6.0 million of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008.
Operating and Maintenance Expense — Operating and maintenance expense increased in 2009 compared to 2008 due to property taxes, partially offset by our cost reduction initiatives.
Other — Other operating income in 2008 related to payment received from a supplier regarding the early termination of its supply agreement.
Propane Sales Volume — Propane sales volumes increased 6% in 2009 compared to 2008.
20
Results of Operations — NGL Logistics Segment
This segment includes our Seabreeze, Wilbreeze and Wattenberg NGL and Black Lake transportation pipelines:
| Year Ended December 31, | Variance 2010 vs. 2009 |
Variance 2009 vs. 2008 |
||||||||||||||||||||||||||
| 2010 (a) |
2009 | 2008 | Increase (Decrease) |
Percent | Increase (Decrease) |
Percent | ||||||||||||||||||||||
| (Millions, except operating data) | ||||||||||||||||||||||||||||
| Operating revenues: |
||||||||||||||||||||||||||||
| Sales of NGLs |
$ | 4.7 | $ | 3.0 | $ | 5.4 | $ | 1.7 | 57 | % | $ | (2.4 | ) | (44 | )% | |||||||||||||
| Transportation, processing and other |
12.9 | 7.5 | 5.9 | 5.4 | 72 | % | 1.6 | 27 | % | |||||||||||||||||||
| Total operating revenues |
17.6 | 10.5 | 11.3 | 7.1 | 68 | % | (0.8 | ) | (7 | )% | ||||||||||||||||||
| Purchases of NGLs |
4.7 | 2.9 | 4.2 | 1.8 | 62 | % | (1.3 | ) | (31 | )% | ||||||||||||||||||
| Segment gross margin (b) |
12.9 | 7.6 | 7.1 | 5.3 | 70 | % | 0.5 | 7 | % | |||||||||||||||||||
| Operating and maintenance expense |
(3.7 | ) | (1.2 | ) | (1.0 | ) | 2.5 | 208 | % | 0.2 | 20 | % | ||||||||||||||||
| Depreciation and amortization expense |
(2.6 | ) | (1.4 | ) | (1.4 | ) | 1.2 | 86 | % | — | — | % | ||||||||||||||||
| Step acquisition – equity interest re-measurement gain |
9.1 | — | — | 9.1 | 100 | % | — | — | % | |||||||||||||||||||
| Earnings from unconsolidated affiliates (c) |
0.8 | 1.9 | 0.8 | (1.1 | ) | (58 | )% | 1.1 | 138 | % | ||||||||||||||||||
| Segment net income attributable to partners |
$ | 16.5 | $ | 6.9 | $ | 5.5 | $ | 9.6 | 139 | % | $ | 1.4 | 25 | % | ||||||||||||||
| Operating data: |
||||||||||||||||||||||||||||
| NGL pipelines throughput (Bbls/d) (c) |
38,282 | 30,160 | 31,407 | 8,122 | 27 | % | (1,247 | ) | (4 | )% | ||||||||||||||||||
| (a) | Includes the results of our Wattenberg pipeline acquired from Buckeye Partners, L.P, since January 28, 2010, the date of acquisition, and an additional 50% interest in Black Lake acquired from an affiliate of BP PLC, since July 30, 2010 the date of acquisition. |
The acquisition of an additional 50% interest in Black Lake brought our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.
The impact to our results related to Marysville, acquired on December 30, 2010, is not significant.
| (b) | Segment gross margin consists of total operating revenues less purchases of NGLs. Please read “How We Evaluate Our Operations” above. |
| (c) | For periods prior to July 30, 2010, includes our 50% share of the throughput volumes and earnings for Black Lake. Black Lake’s earnings included the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment. |
21
Year Ended December 31, 2010 vs. Year Ended December 31, 2009
Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition, our acquisition of an additional 50% interest in Black Lake. 2009 results include the first quarter impact of decreased throughput volumes resulting from ethane rejection and lower volumes at certain connected processing plants.
Segment Gross Margin — Segment gross margin increased in 2010 compared to 2009, as a result of higher volumes from the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake, as well as higher per unit margins.
Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.
Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.
Step acquisition — equity interest re-measurement gain — Step acquisition — equity interest re-measurement gain results from our acquisition of an additional 50% interest in Black Lake bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we remeasured our initial 50% equity interest in Black Lake to its fair value, and recognized a gain of $9.1 million.
NGL Pipelines Throughput — NGL pipelines throughput increased in 2010 compared to 2009, as a result of increased volumes from the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake. 2009 results include the first quarter impact of ethane rejection and lower volumes at certain connected processing plants.
Year Ended December 31, 2009 vs. Year Ended December 31, 2008
Total Operating Revenues — Total operating revenues decreased in 2009 compared to 2008, primarily due to lower throughput volumes, partially offset by higher per unit margins.
Segment Gross Margin — Segment gross margin increased in 2009 compared to 2008, primarily due to higher per unit margins.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2009 compared to 2008, primarily due to decreased operating expenses.
NGL Pipelines Throughput — NGL pipeline throughput decreased in 2009 compared to 2008, due to declines at certain connected processing plants, partially offset by volumes from new interconnects.
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 facility; |
| • | issuance of additional partnership units; |
| • | debt offerings; |
| • | guarantees issued by DCP Midstream, LLC, which reduce the amount of collateral we may be required to post with certain counterparties to our commodity derivative instruments; and |
| • | letters of credit. |
We anticipate our more significant uses of resources to include:
| • | capital expenditures; |
| • | quarterly distributions to our unitholders; |
| • | contributions to our unconsolidated affiliates to finance our share of their capital expenditures; |
| • | business and asset acquisitions; 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 which is required to the extent we exceed certain guarantees issued by DCP Midstream, LLC and letters of credit we have posted. |
22
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.
In 2010, we executed two public equity offerings which generated net proceeds $189.3 million. The proceeds from the equity issuances were used primarily to fund our growth strategy, including acquisitions and organic expansion. The 2010 acquisitions included our purchase of the Wattenberg NGL pipeline, the Chesapeake marine terminal, an additional interest in our Black Lake NGL pipeline and the Marysville NGL storage facility for total cash consideration, net of cash acquired of $203.3 million. Our portion of expansion capital expenditures for 2010 was $30.3 million. Additionally, we used the proceeds to fund our January 2011 $150.0 million acquisition of a 33.3% interest in Southeast Texas from DCP Midstream, LLC. The balance of the capital requirements were funded through borrowing on our revolving credit facility.
Based on current and anticipated levels of operations, we believe we have adequate committed financial resources to conduct our business, although deterioration in our operating environment could limit our borrowing capacity, raise our financing costs, as well as impact our compliance with our financial covenant requirements under our Credit Agreement. Our sources of funding could include additional borrowings under our Credit Agreement, the placement of public and private debt, and the issuance of our common units.
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 portion of our anticipated commodity price risk associated with the equity volumes from our gathering and processing activities through 2015 with fixed price commodity swaps and collar arrangements. For additional information regarding our derivative activities, please read “— Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk — Commodity Cash Flow Protection Activities.”
Our banking group is comprised of various financial institutions, of which certain institutions have recently merged. We do not expect the aggregate contractual financial commitment of these institutions to us to change during the remaining life of our existing credit agreement as a result of these mergers.
Our Credit Agreement consists of a revolving credit facility with capacity of $850.0 million, which matures on June 21, 2012. As of December 31, 2010, the outstanding balance on the revolving credit facility was $398.0 million resulting in unused revolver capacity of $419.9 million, of which approximately $265.0 million was available for general working capital purposes. Effective June 28, 2010, we transferred both the funded and the unfunded portions of the former Lehman Brothers Commercial Bank’s commitment to Morgan Stanley. The transfer reinstated $25.4 million of available capacity to our revolving credit facility.
Our borrowing capacity is currently 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 June 21, 2012 maturity date. As of February 25, 2011, we had approximately $324.5 million of unused capacity under the Credit Agreement.
On May 26, 2010, we filed a universal shelf registration statement on Form S-3 with the SEC with a maximum aggregate offering price of $1.5 billion, to replace an existing shelf registration statement. The universal shelf registration statement will allow us to register and issue additional common units and debt securities.
In August 2010, we issued 2,990,000 common units at $32.57 per unit. We received proceeds of $93.1 million, net of offering costs, which we used to repay funds borrowed under the revolver portion of our Credit Facility.
In September 2010, we issued $250.0 million of 3.25% Senior Notes due October 1, 2015. We received net proceeds, after deducting underwriting discounts and offering expenses, of $247.7 million, which we used to repay funds borrowed under the revolver portion of our Credit Facility.
In November 2010, we issued 2,875,000 common units at $34.96 per unit. We received proceeds of $96.2 million, net of offering costs, which we used to fund the Southeast Texas acquisition.
The counterparties to each 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
23
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 single pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same counterparty. As of February 25, 2011, DCP Midstream, LLC had issued and outstanding parental guarantees totaling $75.0 million in favor of certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with these counterparties. We pay DCP Midstream, LLC a fee of 0.50% per annum on $75.0 million of these guarantees. As of February 25, 2011, we had a contingent issuance letter of credit facility for up to $10.0 million, on which we pay a fee of 0.50% per annum. As of February 25, 2011, we had no letters of credit issued on this facility; we will pay a net fee of 1.75% per annum on letters of credit issued on this facility. These parental guarantees and contingent issuance letter of credit facility reduce the amount of cash we may be required to post as collateral. This contingent issuance letter of credit facility was issued directly by a financial institution and does not reduce the available capacity under our credit facility. As of February 25, 2011, we had no cash collateral posted with counterparties. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis. Predetermined collateral thresholds for certain commodity derivative instruments guaranteed by us or DCP Midstream, LLC are generally dependent on our or DCP Midstream, LLC’s credit ratings and the thresholds could be reduced to $0 in the event that our individual credit ratings were to fall below investment grade.
Discovery is owned 40% by us and 60% by Williams Partners, LP. Discovery is managed by a two-member management committee, consisting of one representative from each owner. The members of the management committee have voting power corresponding to their respective ownership interests in Discovery. All actions and decisions relating to Discovery require the unanimous approval of the owners except for a few limited situations. Discovery must make quarterly distributions of available cash (generally, cash from operations less required and discretionary reserves) to its owners. The management committee, by majority approval, will determine the amount of the distributions. In addition, the owners are required to offer to Discovery all opportunities to construct pipeline laterals within an “area of interest.” Calls for capital contributions are determined by a vote of the management committee and require unanimous approval of both owners in most instances.
East Texas is owned 50.1% by us and 49.9% by DCP Midstream, LLC. East Texas is managed by a four-member management committee, consisting of two representatives from each owner. The members of the management committee have voting power corresponding to their respective ownership interests in East Texas. East Texas must make quarterly distributions of available cash (generally, cash from operations less required and discretionary reserves) to its owners. The management committee, by majority approval, will determine the amount of the distributions. Calls for capital contributions are determined by a vote of the management committee and require unanimous approval of both owners except in certain situations, such as the breach or default of a material agreement or payment obligation, that are reasonably likely to have a material adverse effect on the business, operations or financial condition of East Texas.
Southeast Texas is owned 33.33% by us and 66.67% by two wholly-owned subsidiaries of DCP Midstream, LLC. Southeast Texas is managed by a three-member management committee, consisting of one representative appointed by us and two representatives from DCP Midstream, LLC. The members of the management committee have voting power corresponding to their respective ownership interests in Southeast Texas. Southeast Texas must make quarterly distributions of available cash (generally, cash from operations less required and discretionary reserves) to its owners. In the event Southeast Texas has insufficient available cash for a quarterly distribution (including pursuant to our fee-based arrangement), DCP Midstream, LLC will assign its distribution rights, or contribute any distribution deficiency to Southeast Texas, the sole use of which shall be to pay the distribution deficiency owing to us related to our fee-based arrangement on storage and transportation gross margin, based on storage capacity and tailgate volumes. The management committee, by majority approval, will determine the amount of the distributions. Calls for capital contributions are determined by a vote of the management committee and require unanimous approval of the owners except in certain situations, such as the breach or default of a material agreement or payment obligation, that are reasonably likely to have a material adverse effect on the business, operations or financial condition of Southeast Texas.
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 restricted investments and other long-term assets.
We had working capital of $20.8 million as of December 31, 2010 and $6.6 million as of December 31, 2009. Included in these working capital amounts are net derivative working capital liabilities of $41.1 million and $34.2 million as of December 31, 2010 and December 31, 2009, respectively. The change in working capital is primarily attributable to the factors described above. We expect that our future working capital requirements will be impacted by these same factors.
As of December 31, 2010, we had $6.7 million in cash and cash equivalents. Of this balance, as of December 31, 2010, $0.8 million was held by subsidiaries we do not wholly own, which we consolidate in our financial results. Other than the cash held by these subsidiaries, this cash balance was available for general corporate purposes. Congress recently passed the Dodd-Frank Wall Street Reform and Consumer Protection Act, which has the potential to impact our cash collateral requirements for our derivative positions depending on the final regulations adopted by the United States Commodity Futures Trading Commission and the SEC.
24
Cash Flow — Operating, investing and financing activities was as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
| Net cash provided by operating activities |
$ | 139.7 | $ | 117.3 | $ | 194.0 | ||||||
| Net cash used in investing activities |
$ | (267.9 | ) | $ | (163.8 | ) | $ | (192.2 | ) | |||
| Net cash provided by (used in) financing activities |
$ | 132.8 | $ | (13.3 | ) | $ | 30.8 | |||||
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 paid net cash for settlement of our commodity derivative instruments of $3.6 million for the year ended December 31, 2010, net of cash receipts of $6.2 million of which was associated with rebalancing our portfolio, and received cash for settlement of our commodity derivative instruments for the year ended December 31, 2009 of $16.6 million, approximately $4.8 million of which was associated with rebalancing our portfolio. In addition, we received $3.6 million from DCP Midstream, LLC, related to the sale of surplus equipment as of December 31, 2010, which has been treated as an operating cash flow, because the title to the equipment was not transferred to DCP Midstream, LLC as of the balance sheet date.
We and our predecessors received cash distributions from unconsolidated affiliates of $28.9 million, $29.6 million and $54.8 million during the years ended December 31, 2010, 2009 and 2008, respectively. Earnings exceeded distributions by $9.3 million for the year ended December 31, 2010 and distributions exceeded earnings by $2.7 million and $25.2 million for the years ended December 31, 2009 and 2008, respectively.
Net Cash Used in Investing Activities — Net cash used in investing activities during 2010 was comprised of: (1) acquisition expenditures of $203.3 million related to our acquisition of Atlantic Energy, the Wattenberg NGL pipeline, Marysville and an additional 55% interest in Black Lake; (2) capital expenditures of $50.7 million (our portion of which was $35.9 million and the noncontrolling interest holders’ portion was $14.8 million); (3) investments in Southeast Texas of $26.3 million to fund our portion of the acquisition of the Raywood processing plant and Liberty gathering system; and (4) investments in Discovery of $2.3 million; partially offset by (5) net proceeds from sale of available-for-sale securities of $10.1 million; (6) proceeds from sale of assets of $3.4 million; and (7) a return of investment from Discovery of $1.2 million.
Net cash used in investing activities during 2009 was primarily used for: (1) capital expenditures of $164.8 million (our portion of which was $79.7 million and the noncontrolling interest holders’ portion was $85.1 million), which primarily consisted of expenditures for installation of compression and expansion of our East Texas system, expansion of our Colorado system, and the completion of pipeline integrity system upgrades to our Wyoming system; (2) acquisition expenditure of $44.5 million, primarily related to the acquisition of certain companies that held natural gas gathering and treating assets from MichCon Pipeline Company of $45.1 million; and (3) investments in Discovery of $7.0 million, partially offset by (4) net proceeds from sale of available-for-sale securities of $50.0 million; (5) a return of investment from Discovery of $2.2 million; and (6) proceeds from sale of assets of $0.3 million.
Net cash used in investing activities during 2008 was primarily used for: (1) acquisition of MPP of $146.4 million; acquisition of the MEG subsidiaries of $10.9 million; (2) capital expenditures of $72.7 million (our portion of which was $42.8 million and the noncontrolling interest holders’ portion was $29.9 million), which generally consisted of expenditures for construction and expansion of our infrastructure in addition to well connections and other upgrades to our existing facilities, including the pipeline integrity costs and system upgrades at our Wyoming system; and (3) investments in unconsolidated affiliates of $7.4 million, which were partially offset by (4) net proceeds from available-for-sale securities of $42.3 million; and (5) $2.9 million proceeds from the sale of assets.
25
Net Cash Provided By (Used in) Financing Activities — Net cash provided by financing activities during 2010 was comprised of: (1) borrowings of $868.2 million; (2) proceeds from the issuance of common units net of offering costs of $189.3 million; (3) contributions from noncontrolling interests of $13.8 million; (4) net changes in advances to predecessor from DCP Midstream, LLC of $27.4 million (of which $26.3 million was to fund the acquisition of the Raywood processing plant and Liberty gathering system by Southeast Texas); and (5) contributions from DCP Midstream, LLC of $0.6 million; partially offset by (6) repayments of debt of $833.4 million; (7) distributions to our unitholders and general partner of $101.9 million; (8) distributions to noncontrolling interests of $25.6 million; (9) purchase of additional interest in a subsidiary of $3.5 million; and (10) payment of deferred financing costs of $2.1 million.
During 2010, total outstanding indebtedness under our $850.0 million Credit Agreement, which includes borrowings under our revolving credit facility, our term loan facility and letters of credit issued under the Credit Agreement, was not less than $300.5 million and did not exceed $722.4 million. The weighted-average indebtedness outstanding under the revolving credit facility was $622.5 million, $625.9 million, $634.7 million and $347.9 million for the first, second, third and fourth quarters of 2010, respectively.
We had unused revolver capacity, which is available commitments under the Credit Agreement of $209.3 million, $234.6 million, $486.5 million and $419.9 million at the end of the first, second, third and fourth quarters of 2010, respectively.
During 2010, we had the following net movements on our revolving credit facility:
| • | $247.7 million repayment financed by the issue of $250.0 million of 3.25% Senior Notes due October 1, 2015; |
| • | $93.1 million repayment financed by the issue of 2,990,000 common units in August 2010; and |
| • | $96.2 million repayment financed by the issue of 2,875,000 common units in November 2010; partially offset by |
| • | $66.3 million borrowing to fund the acquisition of Atlantic Energy, which includes $17.3 million for propane inventory and working capital; |
| • | $16.3 million net borrowings for general corporate purposes; |
| • | $22.0 million borrowing to fund the acquisition of the Wattenberg pipeline; |
| • | $16.6 million borrowing to fund the acquisition of an additional 55% interest in Black Lake; |
| • | $100.8 million borrowing to fund the acquisition of Marysville, which includes $6.0 million for inventory and working capital; and |
| • | $10.0 million borrowing to fund repayment of our term loan facility. |
During 2010, we had a repayment of $10.0 million on our term loan facility and released $10.0 million of restricted investments which were required as collateral for the facility.
Net cash used in financing activities during 2009 was comprised of: (1) repayments of debt of $280.5 million; (2) distributions to our unitholders and general partner of $85.3 million; (3) distributions to noncontrolling interests of $27.0 million; and (4) net changes in advances to predecessor from DCP Midstream, LLC of $6.4 million, partially offset by (5) borrowings of $237.0 million; (6) contributions from noncontrolling interests of $78.7 million; (7) the issuance of common units for $69.5 million, net of offering costs; and (8) contributions from DCP Midstream, LLC of $0.7 million.
During 2009, total outstanding indebtedness under our $850.0 million Credit Agreement, which includes borrowings under our revolving credit facility, our term loan facility and letters of credit issued under the credit agreement, was not less than $608.3 million and did not exceed $656.8 million. The weighted average indebtedness outstanding was $656.7 million, $644.4 million, $638.3 million and $620.4 million for the first, second, third and fourth quarters of 2009, respectively.
We had liquidity, which is available commitments under the Credit Agreement of $239.3 million, $221.3 million, $221.3 million and $221.3 million at the end of the first, second, third and fourth quarters of 2009, respectively.
26
During 2009, we had the following net movements on our Credit Agreement:
| • | $50.0 million borrowing under our revolving credit facility to fund a partial repayment of our term loan facility; partially offset by |
| • | $43.5 million repayment under our revolving credit facility. |
Net cash provided by financing activities during 2008 was comprised of: (1) proceeds from debt of $660.4 million; (2) the issuance of common units for $132.1 million, net of offering costs; (3) contributions from noncontrolling interests of $21.3 million; (4) contributions from DCP Midstream, LLC of $4.1 million, partially offset by (5) repayment of debt of $633.9 million; (6) distributions to our unitholders and general partner of $76.2 million; (7) distributions to noncontrolling interests of $46.4 million; and (8) net changes in advances from DCP Midstream, LLC relating to our predecessor of $30.6 million.
During 2008, total outstanding indebtedness under our $850.0 million Credit Agreement, which includes borrowings under our revolving credit facility, our term loan facility and letters of credit issued under the credit agreement, was not less than $630.2 million and did not exceed $735.3 million. The weighted average indebtedness outstanding was $643.1 million, $690.0 million, $655.4 million and $666.6 million for the first, second, third and fourth quarters of 2008, respectively.
We had liquidity, which is available commitments under the Credit Agreement, of $364.7 million, $385.4 million, $390.4 million and $228.0 million at the end of the first, second, third and fourth quarters of 2008, respectively.
During 2008, we had the following net movements on our Credit Agreement:
| • | $146.4 million borrowing under our revolving credit facility which was used for the Michigan acquisition; partially offset by |
| • | $79.9 million repayment under our revolving credit facility. |
During 2008, we repaid $40.0 million under our term loan facility
We expect to continue to use cash in financing activities for the payment of distributions to our unitholders and general partner. See Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
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:
| • | maintenance capital expenditures, which are cash expenditures where we add on to or improve capital assets owned, including certain system integrity and safety improvements, or acquire or construct new capital assets if such expenditures are made to maintain, including over the long term, our operating capacity or revenues; and |
| • | expansion capital expenditures, which are cash expenditures for acquisitions or capital improvements (where we add on to or improve the capital assets owned, or acquire or construct new gathering lines, 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) in each case if such addition, improvement, acquisition or construction is made to increase our operating capacity or revenues. |
We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance capital expenditures of between $10.0 million and $15.0 million, and expenditures for expansion capital of between $35.0 million and $50.0 million, for the year ending December 31, 2011 including $10.0 million for the expansion to storage capacity at our Southeast Texas system. The board of directors may approve additional growth capital during the year, at their discretion.
The following table summarizes our maintenance and expansion capital expenditures for our consolidated entities.
| Year Ended December 31, 2010 | Year Ended December 31, 2009 | |||||||||||||||||||||||
| Maintenance Capital Expenditures |
Expansion Capital Expenditures |
Total Consolidated Capital Expenditures |
Maintenance Capital Expenditures |
Expansion Capital Expenditures |
Total Consolidated Capital Expenditures |
|||||||||||||||||||
| (Millions) | (Millions) | |||||||||||||||||||||||
| Our portion |
$ | 5.6 | $ | 30.3 | $ | 35.9 | $ | 12.6 | $ | 67.1 | $ | 79.7 | ||||||||||||
| Noncontrolling interest portion |
6.4 | 8.4 | 14.8 | 21.3 | 63.8 | 85.1 | ||||||||||||||||||
| Total |
$ | 12.0 | $ | 38.7 | $ | 50.7 | $ | 33.9 | $ | 130.9 | $ | 164.8 | ||||||||||||
27
| Year Ended December 31, 2008 | ||||||||||||
| Maintenance Capital Expenditures |
Expansion Capital Expenditures |
Total Consolidated Capital Expenditures |
||||||||||
| (Millions) | ||||||||||||
| Our portion |
$ | 13.6 | $ | 29.2 | $ | 42.8 | ||||||
| Noncontrolling interest portion |
11.5 | 18.4 | 29.9 | |||||||||
| Total |
$ | 25.1 | $ | 47.6 | $ | 72.7 | ||||||
In addition, we invested cash in unconsolidated affiliates of $28.6 million, $7.0 million and $7.4 million during the years ended December 31, 2010, 2009 and 2008, respectively, of which $2.3 million, $2.8 million and $5.8 million, respectively, was to fund our share of capital expansion projects, and $4.2 million in 2009, was to fund repairs to Discovery following damage caused by hurricane Ike in 2008 (of which $1.2 million and $2.2 million was returned to us by Discovery during 2010 and 2009, respectively).
Capital expenditures decreased in 2010 compared to 2009 as a result of the substantial completion during 2009 of our expansion projects in our Colorado and East Texas systems.
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 could 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 facility, issuance of long-term debt and the issuance of additional partnership units. 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, including payment to our general partner related to our incentive distribution rights, of $101.9 million, $85.3 million and $76.2 million during 2010, 2009 and 2008, 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 an $850.0 million revolving credit at December 31, 2010. The Credit Agreement matures on June 21, 2012. As of December 31, 2010, the outstanding balance on the revolving credit facility was $398.0 million resulting in unused revolver capacity of $419.9 million, of which approximately $265.0 million was available for general working capital purposes. The term loan was repaid during the first quarter of 2010.
Our obligations under the revolving credit facility are unsecured. The term loan facility, which was repaid during the first quarter of 2010, was secured at all times by high-grade securities, which we classified as restricted investments in the accompanying consolidated balance sheets, in an amount equal to or greater than the outstanding principal amount of the term loan. Any portion of the term loan balance may be repaid at any time, and we would then have access to a corresponding amount of the collateral securities. Upon any prepayment of term loan borrowings, the amount of our revolving credit facility will automatically increase to the extent that the repayment of our term loan facility is made in connection with an acquisition or construction of assets in the midstream energy business. The unused portion of the revolving credit facility may be used for letters of credit. At December 31, 2010 and 2009, we had outstanding letters of credit issued under the Credit Agreement of $32.1 million and $0.3 million, respectively.
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 revolving credit facility bears interest at either: (1) the higher of Wells Fargo Bank’s prime rate or the Federal Funds rate plus 0.50%; or (2) LIBOR plus an applicable margin, which ranges from 0.23% to 0.575% dependent upon our credit rating. As of December 31, 2010, the weighted-average interest rate on our revolving credit facility was 1.14% per annum. The revolving credit facility incurs an annual facility fee of 0.07% to 0.175% depending on our credit rating. This fee is paid on drawn and undrawn portions of the revolving credit facility. The term loan facility bears interest at a rate equal to either: (1) LIBOR plus 0.10%; or (2) the higher of Wells Fargo Bank’s prime rate or the Federal Funds rate plus 0.50%.
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.
28
Description of Debt Securities
On September 30, 2010, we issued $250.0 million of 3.25% Senior Notes due October 1, 2015. We received net proceeds of $247.7 million, net of underwriters’ fees, related expense and unamortized discounts of $1.5 million, $0.6 million and $0.2 million, respectively which we used to repay funds borrowed under the revolver portion of our Credit Facility. Interest on the notes will be paid semi-annually on April 1 and October 1 of each year, commencing April 1, 2011. The notes will mature on October 1, 2015 unless redeemed prior to maturity.
We incurred $2.1 million of underwriters’ fees and related expense with the issue of the notes, which we deferred in other long term assets in our consolidated balance sheets. We will amortize these costs over the term of the notes.
The 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 these notes. The securities 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, 2010, is as follows:
| Payments Due by Period | ||||||||||||||||||||
| Total | 2011 | 2012-2013 | 2014-2015 | 2016 and Thereafter |
||||||||||||||||
| (Millions) | ||||||||||||||||||||
| Long-term debt (a) |
$ | 735.1 | $ | 33.2 | $ | 432.8 | $ | 269.1 | $ | — | ||||||||||
| Operating lease obligations (b) |
43.8 | 15.8 | 22.1 | 4.7 | 1.2 | |||||||||||||||
| Purchase obligations (c) |
614.0 | 324.0 | 176.0 | 65.4 | 48.6 | |||||||||||||||
| Other long-term liabilities (d) |
12.1 | — | 0.5 | 0.3 | 11.3 | |||||||||||||||
| Total |
$ | 1,405.0 | $ | 373.0 | $ | 631.4 | $ | 339.5 | $ | 61.1 | ||||||||||
| (a) | Includes interest payments on long-term debt that has been hedged and on debt securities that have been issued. These interest payments are $33.2 million, $34.8 million and $19.1 million for 2011, 2012-2013 and 2014-2015, respectively. Interest payments on long-term debt that has not been hedged are not included as these payments are based on floating interest rates and we cannot determine with accuracy the periodic repayment dates or the amounts of the interest payments. |
| (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 firm transportation arrangements and natural gas storage for our Pelico system. The firm transportation arrangements supply off-system natural gas to Pelico and 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. |
29
| (c) | Our purchase obligations are contractual obligations and include $3.8 million of purchase orders for capital expenditures and $610.2 million of various non-cancelable commitments to purchase physical quantities of propane supply for our Wholesale Propane Logistics business. For contracts where the price paid is based on an index, the amount is based on the forward market prices at December 31, 2010. 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. |
| (d) | Other long-term liabilities include $10.8 million of asset retirement obligations and $1.3 million of environmental reserves recognized in the consolidated balance sheet at December 31, 2010. |
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 Item 8. “Financial Statements and Supplementary Data.”
| 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, 2010 weighted-average cost, our net income would be affected by approximately $6.5 million. | ||
30
| Description |
Judgments and Uncertainties |
Effect if Actual Results Differ from Assumptions | ||
| 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 allocating 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 completed our impairment testing of goodwill using the methodology described herein, and determined there was no impairment. Key assumptions in the analysis include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices and throughput volumes. 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 goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. We have not recorded any impairment charges on goodwill during the year ended December 31, 2010. The carrying value of goodwill as of December 31, 2010 by reporting unit was $52.8 million for our Colorado system, $36.9 million for our Wholesale Propane Logistics business and $10.0 million for our Michigan system, totaling $99.7 million. | ||
| 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 may 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. 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 allocating 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, 2010. 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. The carrying value of our long-lived assets as of December 31, 2010 was $1,256.1 million. | ||
31
| Description |
Judgments and Uncertainties |
Effect if Actual Results Differ from Assumptions | ||
| 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 loss calculations 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. 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, 2010. 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. The carrying value of our unconsolidated affiliates as of December 31, 2010 was $104.3 million. | ||
| 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 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, 2010 would have affected net income by approximately $7.2 million for the year ended December 31, 2010. | ||
| Accounting for Equity-Based Compensation | ||||
| Our long-term incentive plan permits for the grant of restricted units, phantom units, unit options and substitute awards. Equity-based compensation expense is recognized over the vesting period or service period of the related awards. We estimate the fair value of each award, and the number of awards that will ultimately vest, at the end of each period. | Estimating the fair value of each award, the number of awards that will ultimately vest, and the forfeiture rate requires management to apply judgment to estimate the tenure of our employees and the achievement of certain performance targets over the performance period. | 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 compensation expense. | ||
32
| Description |
Judgments and Uncertainties |
Effect if Actual Results Differ from Assumptions | ||
| 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 increases 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, 2010 would impact our net income by approximately $0.1 million. | ||
33
Recent Accounting Pronouncements
Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2010-29 “Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations”, or ASU 2010-29 — In December 2010, the FASB issued ASU 2010-29 which amended Accounting Standards Codification, or ASC, Topic 805 “Business Combinations” to specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the year had occurred as of the beginning of the comparable prior annual reporting period only. The ASU also expands the supplemental pro forma disclosures under Topic 805 to include a description of the nature and the amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective for business combinations for which the acquisition date is on or after January 1, 2011 and we will disclose information in accordance with the ASU within all financial statements issued after the effective date.
ASU 2010-28 “Intangibles—Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”, or ASU 2010-28 — In December 2010, the FASB issued ASU 2010-28 which amended ASC Topic 350 “Goodwill and Other.” ASU 2010-28 requires an entity with reporting units that have carrying amounts that are zero or negative to assess whether it is more likely than not that the reporting units’ goodwill is impaired. If the entity determines that it is more likely than not that the goodwill of one or more of its reporting units is impaired, the entity is required to perform Step 2 of the goodwill impairment test for those reporting unit(s) and record any resulting impairment as a cumulative-effect adjustment to beginning retained earnings. The provisions of ASU 2010-28 became effective for us on January 1, 2011, and we will disclose information in accordance with the ASU within all financial statements issued after the effective date.
ASU 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements”, or ASU 2010-06 — In January 2010, the FASB issued ASU 2010-06 which amended ASC Topic 820-10 “Fair Value Measurement and Disclosures—Overall.” ASU 2010-06 requires new disclosures regarding transfers in and out of assets and liabilities measured at fair value classified within the valuation hierarchy as either Level 1 or Level 2 and information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3. ASU 2010-06 clarifies existing disclosures on the level of disaggregation required and inputs and valuation techniques. The provisions of ASU 2010-06 became effective for us on January 1, 2010, except for disclosure of information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3, which is effective for us on January 1, 2011. The provisions of ASU 2010-06 impact only disclosures and we have disclosed information in accordance with the revised provisions of ASU 2010-06 within this filing.
ASU 2009-17 “Consolidation (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities”, or ASU 2009-17 — In December 2009, the FASB issued ASU 2009-17 which amended ASC Topic 810 “Consolidation.” ASU 2009-17 requires entities to perform additional analysis of their variable interest entities and consolidation methods. This ASU became effective for us on January 1, 2010 and upon adoption we did not change our conclusions on which entities we consolidate in our consolidated financial statements.
ASU 2009-13 “Revenue Recognition (Topic 605) Multiple-Deliverable Revenue Arrangements”, or ASU 2009-13 — In October 2009, the FASB issued ASU 2009-13 which amended ASC Topic 605 “Revenue Recognition.” The ASU addresses the accounting for multiple-deliverable arrangements, to enable vendors to account for products or services separately rather than as a combined unit. ASU 2009-13 became effective for us on January 1, 2011 and there was no impact on our consolidated results of operations, cash flows and financial position as a result of adoption.
Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse change in market prices and rates. We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as forward contracts, swaps and futures to mitigate a portion of the effects of identified risks. In general, we attempt to mitigate a portion of the risks related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements.
Risk Management Policy
We have established a comprehensive risk management policy, or Risk Management Policy, and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. Our Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.
See Note 12, Risk Management and Hedging Activities, of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the accounting for derivative contracts.
34
Credit Risk
Our principal customers in the Natural Gas Services segment are large, natural gas marketing servicers and industrial end-users. Our principal customers in the Wholesale Propane Logistics segment are primarily retail propane distributors. In the NGL Logistics Segment, our principal customers include an affiliate of DCP Midstream, LLC, producers and marketing companies. Substantially all of our natural gas, propane and NGL sales are made at market-based prices. This concentration of credit risk may affect our overall credit risk, as these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits, and monitor the appropriateness of these limits on an ongoing basis. We operate under DCP Midstream, LLC’s corporate credit policy. DCP Midstream, LLC’s corporate credit policy, as well as the standard terms and conditions of our agreements, prescribe the use of financial responsibility and reasonable grounds for adequate assurances. These provisions allow our credit department to request that a counterparty remedy credit limit violations by posting cash or letters of credit for exposure in excess of an established credit line. The credit line represents an open credit limit, determined in accordance with DCP Midstream, LLC’s credit policy. Our standard agreements also provide that the inability of a counterparty to post collateral is sufficient cause to terminate a contract and liquidate all positions. The adequate assurance provisions also allow us to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment to us in a satisfactory form.
Interest Rate Risk
Interest rates on future credit facility draws and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.
We mitigate a portion of our interest rate risk with interest rate swaps, which reduce our exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. These interest rate swap agreements convert the interest rate associated with the indebtedness outstanding under our revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations.
At December 31, 2010, we had interest rate swap agreements totaling $450.0 million, of which we have designated $275.0 million as cash flow hedges and account for the remaining $175.0 million under the mark-to-market method of accounting. As we expect to have variable rate debt levels equal to or exceeding our swap positions during their term, the entire $450.0 million of these agreements mitigate our interest rate risk through June 2012, with $150.0 million extending from June 2012 through June 2014. Based on our current operations we believe our interest rate swap agreements adequately mitigate our interest rate risk associated with our variable rate debt. As of February 25, 2011, we had interest rate swap agreements totaling $450.0 million, of which we have designated $425.0 million as cash flow hedges and account for the remaining $25.0 million under the mark-to-market method of accounting.
At December 31, 2009, we had interest rate swap agreements totaling $575.0 million, all of which we had designated as cash flow hedges. In conjunction with the issuance of $250.0 million of 3.25% Senior Notes, we paid down our revolving credit facility, discontinued hedge accounting on $225.0 million of our existing swap agreements, terminated certain swap agreements for $1.3 million, and modified certain swap agreements to reduce the total outstanding amount by $125.0 million. Additionally, the term on $150.0 million of the swap agreements was extended through June 2014. This resulted in $450.0 million of these swap agreements mitigating our interest rate risk through June 2012, with $150.0 million extending from June 2012 through June 2014.
At December 31, 2010, the effective weighted-average interest rate on our outstanding debt was 4.42%, taking into account our interest rate swap agreements totaling $450.0 million.
Based on the annualized unhedged borrowings under our credit facility of $123.0 million as of December 31, 2010, a 0.5% movement in the base rate or LIBOR rate would result in an approximately $0.6 million annualized increase or decrease in interest expense.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering services, we receive fees or commodities from producers to bring the natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, depending on the types of contracts. We employ established policies and procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including forward contracts, swaps and futures.
35
Commodity Cash Flow Protection Activities — We closely monitor the risks associated with commodity price changes on our future operations and, where appropriate, use various fixed price swaps and collar arrangements to mitigate a portion of the effect pricing fluctuations may have on the value of our assets and operations. Depending on our risk management objectives, we may periodically settle a portion of these instruments prior to their maturity.
We enter into derivative financial instruments to mitigate a portion of the cash flow risk of decreased natural gas, NGL and condensate prices associated with our percent-of-proceeds arrangements and gathering operations. We also may enter into natural gas derivatives to lock in margin around our transportation or leased storage assets. Historically, there has been a strong relationship between NGL prices and crude oil prices, with some recent exceptions and lack of liquidity in the NGL financial market; therefore we have historically used crude oil swaps and costless collars to mitigate a portion of NGL price risk. When the relationship of NGL prices to crude oil prices is at a discount to historical ranges, we experience additional exposure as a result of the relationship. As a result of these transactions, we have mitigated a portion of our expected natural gas, NGL and condensate commodity price risk through 2015.
The derivative financial instruments we have entered into are typically referred to as “swap” contracts and “collar” arrangements. These swap contracts entitle us to receive payment at settlement from the counterparty to the contract to the extent that the reference price is below the swap price stated in the contract, and we are required to make payment at settlement to the counterparty to the extent that the reference price is higher than the swap price stated in the contract.
We are using the mark-to-market method of accounting for all commodity derivative instruments, which has significantly increased the volatility of our results of operations as we recognize, in current earnings, all non-cash gains and losses from the mark-to-market on derivative activity.
We also use commodity collar arrangements which include the combination of a sold call and a purchased put. The sold call establishes the maximum prices that we will receive for contracted commodity volumes, and the purchased put establishes the minimum price that we will receive.
The following tables set forth additional information about our fixed price swaps and collar arrangements used to mitigate a portion of our natural gas and NGL price risk associated with our percent-of-proceeds arrangements and our condensate price risk associated with our gathering operations, as of February 25, 2011:
Commodity Oil Swaps
| Period |
Commodity |
Notional Volume |
Reference Price |
Price Range | ||||
| January 2011 — December 2014 |
Natural Gas | 500 MMBtu/d |
IFERC Monthly Index Price for Colorado Interstate Gas Pipeline (a) | $5.06/MMBtu | ||||
| January 2011 — December 2014 |
Natural Gas | 500 MMBtu/d |
Texas Gas Transmission Price (b) | $4.87/MMBtu | ||||
| March 2011 — December 2011 |
Natural Gas | 400MMBtu/d | IFERC Monthly Index Price for Houston Ship Channel (d) | $4.21/MMBtu | ||||
| January 2011 — December 2011 |
Crude Oil | 2,600 Bbls/d | Asian-pricing of NYMEX crude oil futures (c) | $56.75 - $83.80/Bbl | ||||
| January 2012 — December 2012 |
Crude Oil | 2,325 Bbls/d | Asian-pricing of NYMEX crude oil futures (c) | $66.72 - $99.85/Bbl | ||||
| January 2013 — December 2013 |
Crude Oil | 2,250 Bbls/d | Asian-pricing of NYMEX crude oil futures (c) | $67.60 - $99.85/Bbl | ||||
| January 2014 — December 2014 |
Crude Oil | 1,500 Bbls/d | Asian-pricing of NYMEX crude oil futures (c) | $74.90 - $96.08/Bbl | ||||
| January 2015 — December 2015 |
Crude Oil | 1,000 Bbls/d | Asian-pricing of NYMEX crude oil futures (c) | $92.00 - $100.04/Bbl | ||||
| April 2011 — December 2011 |
NGLs | 405 Bbls/d | Mt. Belvieu Non-TET (e) | $0.55 – $2.38/Gal | ||||
| (a) | The Inside FERC index price for natural gas delivered into the Colorado Interstate Gas (CIG) pipeline. |
| (b) | The Inside FERC index price for natural gas delivered into the Texas Gas Transmission pipeline in the North Louisiana area. |
| (c) | Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract (CL). |
| (d) | The Inside FERC monthly published index price for natural gas delivered into the Houston Ship Channel area. |
| (e) | The average monthly OPIS price for Mt. Belvieu Non-TET. |
36
Commodity Collar Arrangements
| Period |
Commodity | Notional Volume |
Reference Price |
Collar Price Range | ||||
| January 2011 —December 2012 | Crude Oil | 200 Bbls/d (a) | Asian-pricing of NYMEX crude oil futures (b) | $80.00 - $97.40/Bbl | ||||
| (a) | Reflects separate purchased put and sold call contracts, resulting in a collar arrangement. |
| (b) | Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract (CL). |
At December 31, 2010, the aggregate fair value of the fixed price commodity swaps and collar arrangements described above was a net loss of $62.6 million.
Our annual sensitivities for 2011 as shown in the table below, exclude the impact from non-cash mark-to-market on our commodity derivatives. We utilize derivatives to mitigate a portion of our commodity price exposure for NGLs, and show our sensitivity to changes in the relationship between the pricing of NGLs and crude oil. For fixed price natural gas and crude oil, the sensitivities are associated with our unhedged volumes. For our NGL to crude oil price relationship, the sensitivity is associated with both hedged and unhedged equity volumes.
Commodity Sensitivities Excluding Non-Cash Mark-To-Market
| Per Unit Decrease | Unit of Measurement |
Estimated Decrease in Annual Net Income Attributable to Partners |
||||||||||
| (Millions) | ||||||||||||
| Natural gas prices |
$ | 1.00 | MMBtu | $ | 0.4 | |||||||
| Crude oil prices (a) |
$ | 5.00 | Barrel | $ | 2.5 | |||||||
| NGL to crude oil price relationship (b) |
|
5 percentage point change |
|
Barrel | $ | 7.7 | ||||||
| (a) | Assuming 60% NGL to crude oil price relationship. |
| (b) | Assuming 60% NGL to crude oil price relationship and $80.00/Bbl crude oil price. Generally, this sensitivity changes by $1.9 million for each $20.00/Bbl change in the price of crude oil. As crude oil prices increase from $80.00/Bbl, we become slightly more sensitive to the change in the relationship of NGL prices to crude oil prices. As crude oil prices decrease from $80.00/Bbl, we become less sensitive to the change in the relationship of NGL prices to crude oil prices. |
In addition to the linear relationships in our commodity sensitivities above, additional factors cause us to be less sensitive to commodity price declines. A portion of our net income is derived from fee-based contracts and a certain percentage of liquids processing arrangements that contain minimum fee clauses in which our processing margins convert to fee-based arrangements as NGL prices decline.
The above sensitivities exclude the impact from arrangements where producers on a monthly basis may elect to not process their natural gas in which case we retain a portion of the customers’ natural gas in lieu of NGLs as a fee. The above sensitivities also exclude certain related processing arrangements where we control the processing or by-pass of the production based upon individual economic processing conditions. Under each of these types of arrangements, our processing of the natural gas would yield favorable processing margins. Less than 10% of our gas throughput is associated with these arrangements.
37
We estimate the following non-cash sensitivities in 2011 related to the mark-to-market on our commodity derivatives associated with our commodity cash flow protection activities:
Non-Cash Mark-To-Market Commodity Sensitivities
| Per Unit Increase |
Unit of Measurement |
Estimated Mark-to- Market Impact (Decrease in Net Income Attributable to Partners) |
||||||||||
| (Millions) | ||||||||||||
| Natural gas prices |
$ | 1.00 | MMBtu | $ | 1.4 | |||||||
| Crude oil prices |
$ | 5.00 | Barrel | $ | 16.6 | |||||||
| NGL prices |
$ | 0.10 | Gallon | $ | 0.5 | |||||||
While the above commodity price sensitivities are indicative of the impact that changes in commodity prices may have on our annualized net income, changes during certain periods of extreme price volatility and market conditions or changes in the relationship of the price of NGLs and crude oil may cause our commodity price sensitivities to vary significantly from these estimates.
The above Commodity Sensitivities Excluding Non-Cash Mark-to-Market Activity and Non-Cash Mark-to-Market Sensitivities tables exclude our collar arrangements. These collar arrangements represent approximately 5% of our commodity derivative instruments.
The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which in turn has been generally related to the price of crude oil, with some notable exceptions in late 2008 and early 2009, when NGL pricing was at a greater discount to crude oil pricing. 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 natural gas prices being at levels sufficient to provide incentives and capital, for producers to increase natural gas exploration and production. To minimize potential future commodity-based pricing and cash flow volatility, we have entered into a series of derivative financial instruments. As a result of these transactions, we have mitigated a portion of our expected natural gas, NGL and condensate commodity price risk relating to the equity volumes associated with our gathering and processing activities through 2015. Given the historical relationship between NGL prices and crude oil prices and the lack of liquidity in the NGL financial market, we have generally used crude oil derivative instruments to mitigate a portion of NGL price risk. When the relationship of NGL prices to crude oil prices is at a discount to historical ranges, we experience additional exposure as a result of the relationship.
Based on historical trends, we generally expect NGL prices to directionally follow changes in crude oil prices over the long term. However, the pricing relationship between NGLs and crude oil may vary, as we believe crude oil prices will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy, whereas NGL prices are more correlated to supply and U.S. petrochemical demand. We believe that future natural gas prices will be influenced by North American supply deliverability, the severity of winter and summer weather, the level of North American production and drilling activity of exploration and production companies and imports of liquid natural gas, or LNG, from foreign locations. Drilling activity can be adversely affected as natural gas prices decrease. Energy market uncertainty could also further reduce North American drilling activity. Limited access to capital could also decrease drilling. Lower drilling levels over a sustained period would reduce natural gas volumes gathered and processed, but could increase commodity prices, if supply were to fall below demand levels.
Other Asset-Based Activities — Our operations of gathering, processing, and transporting natural gas, and the accompanying operations of transporting, producing and marketing of NGLs create commodity price risk due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and condensate. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. We occasionally will enter into financial derivatives to lock in time spreads and price differentials across the Pelico system to maximize the value of pipeline capacity.
Our wholesale propane logistics business is generally designed to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. Occasionally, we may enter into fixed price sales agreements in the event that a retail propane distributor desires to purchase propane from us on a fixed price basis. We manage this risk with both physical and financial transactions, sometimes using non-trading derivative instruments, which generally allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories.
We manage our commodity derivative activities in accordance with our Risk Management Policy which limits exposure to market risk and requires regular reporting to management of potential financial exposure.
38
Valuation — Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. 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 and expected relationship with quoted market prices.
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. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
The fair value of our interest rate swaps and commodity non-trading derivatives is expected to be realized in future periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events that could impact the amount and/or realization of these values.
| Fair Value of Contracts as of December 31, 2010 | ||||||||||||||||||||
| Sources of Fair Value | Total | Maturity in 2011 |
Maturity in 2012-2013 |
Maturity in 2014-2015 |
Maturity in 2016 and Thereafter |
|||||||||||||||
| (Millions) | ||||||||||||||||||||
| Prices supported by quoted market prices and other external sources |
$ | (90.0 | ) | $ | (41.3 | ) | $ | (43.7 | ) | $ | (5.0 | ) | $ | — | ||||||
| Prices based on models or other valuation techniques |
$ | — | $ | 0.2 | $ | — | $ | (0.2 | ) | $ | — | |||||||||
| Total |
$ | (90.0 | ) | $ | (41.1 | ) | $ | (43.7 | ) | $ | (5.2 | ) | $ | — | ||||||
The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, our New York Mercantile Exchange, or NYMEX, positions in natural gas, NGLs and crude oil. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from SunGard Kiodex and then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which over-the-counter, or OTC, broker quotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate.
The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point.
39