spectra energy eaf6b568-4ba4-4e99-a365-e9ef8c17dba5_transcript020509

4th Quarter and Year-End 2008 Earnings Review

2009 Outlook

February 5, 2009 John Arensdorf Thank you, Janice, and good morning, everyone. As Janice said, I am John Arensdorf, chief communications officer for Spectra Energy. We are pleased that you could join us today as we share our 2008 fourth quarter and year-end earnings results, as well as our 2009 business plan. Let me briefly review our agenda, and introduce you to today’s speakers. We’re covering a lot of ground this morning, combining our customary fourth quarter discussion with the rollout of our 2009 plan. Greg Ebel will begin our discussion by sharing his perspective on our very successful 2008, and provide an overview of our 2009 business strategy. We will then look forward to introducing you to Pat Reddy, our new CFO, who will share the details around our financial results for the quarter and cover the details of our 2009 financial plan. Next, Tom O’Connor, chairman, president and CEO of DCP Midstream, will provide perspective on our field services business. And then Greg will return to wrap things up and provide his thoughts on what makes Spectra Energy such an attractive investment opportunity. As always, we’ll allow plenty of time for your questions following our prepared presentation. In addition to the slides we’ll cover with you today, you’ll find in the materials on our website an appendix of information that we hope will be helpful to you. As you know, some of what we’ll discuss today concerning future company performance will be forward-looking information within the meanings of the securities laws. Actual results may materially differ from those discussed in these forward-looking statements, and you should refer to the additional information contained in Spectra Energy’s Form 10-K and other filings made with the SEC concerning factors that could cause these results to be different than contemplated

4Q08 Earnings 2009 Outlook February 5, 2009

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in today’s discussion. In addition, today’s discussion will include certain non-GAAP financial measures as defined under SEC Regulation G. A reconciliation of those measures to the most directly comparable GAAP measures is available on our website at spectraenergy.com. With that, let me turn things over to our president and CEO, Greg Ebel. Greg Ebel Thank you, John, and thanks to all of you for joining us today. It is my pleasure to be with you again – this time however as CEO of Spectra Energy. I’m not the only one here in a different role today. We are pleased to have Pat Reddy join us as chief financial officer. Many of you know Pat from his days as senior vice president and CFO at Atmos Energy. During his career with Atmos, Pat also led the corporate development and treasury functions, and before joining Atmos, he served as vice president of planning and advisory services for Pacific Enterprises. I am very pleased to have Pat on board. With all of his great experience he is a strong addition to the Spectra Energy team. As John mentioned, I’m going to spend most of my time with you today delving into the highlights of our 2009 plan, the opportunities and challenges we’ve identified, and our objectives for the short-term. I also want to tell you how Spectra Energy is positioning itself to continue our long-term growth strategy. But first, let’s take a quick review our 2008 accomplishments. Spectra Energy’s 2008 financial and operating results exceeded our expectations.

• Ongoing earnings per share of $1.83 for the year were significantly above the $1.56 EPS employee incentive target that we shared with you about a year ago.

• We increased our dividend 14 percent. • We did a fine job of executing our capital expansion program, placing about $1.8 billion

of projects into service during 2008. And we delivered those projects as scheduled, and they will provide solid returns averaging slightly above our 10 to 12 percent return on capital employed target.

• We have maintained strong liquidity in the midst of a severe credit crunch, and as you

might recall, in early September we moved into the credit markets and got the remainder of our 2008 debt issuances out of the way, about a week before the credit crunch really hit.


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We ended the year with less debt than we originally expected, and we also finished the year with about $200 million of cash on our balance sheet. Let’s take a look at those projects we placed into service last year, all of which will generate 2009 earnings and cash flow. This slide lists the 19 projects we placed into service last year – projects that will deliver total annual EBIT of approximately $225 million this year. We enjoyed EBIT from these projects of about $95 million in 2008 and expect an incremental $130 million in 2009. 2008 was by far our largest capital expansion year, and we are extremely pleased that we were able to get most of the heavy lifting out of the way last year – bringing substantial, value-adding projects into service to meet our customers’ needs and help grow our stable, fee-based EBIT. Pat will share a more details on our 2008 performance in a few minutes, so I want to turn now to a top-level look at our 2009. A little later in the call we will go into greater detail regarding our assumptions and related sensitivities, but here are the key highlights: We’ve set our 2009 earnings per share guidance at $1.15 per share, based on $55/barrel oil, with an estimated NGL/Crude relationship of 60 percent; $6.00 natural gas and a $4.75 frac spread at our Empress plant. We’ve also assumed a Canadian FX rate of 1.2 Canadian dollars for every one U.S. dollar. We know that the dividend is a key component of the value shareholders place in Spectra Energy’s common equity, and our annual dividend for 2009 will remain at $1.00 per share. Our 2008 payout came in around 55 percent. 2009’s payout will be considerably higher than our 60 percent long-term payout target, but over time as earnings grow we’ll aim for a return to that type of payout ratio. We previously told you our 2009 growth capex would be about half of what we spent in 2008, or about $800 million. But given the external economic and market dynamics at play, the number now looks like it will be in the $500 million range. We have deferred some capital spending to match our customers’ needs and align with the current market environment. For example, we terminated the Maritimes Phase V project, at our customer’s request, but with no financial exposure to us. We also reduced the size and scope of


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the AGT East to West project and delayed its in-service date to 2010 – again following discussions with our customers. These 2009 capex adjustments do not significantly alter our long-term growth prospects. In fact, we fully expect to proceed with all or most of those projects – as well as new opportunities – once we see a return to more favorable economic conditions. We have a good record of prudently managing our costs, and during these economic times, we’ll redouble those efforts. To that end, we have already taken some important steps, which are reflected in our plan:

We have restricted our salary increases; We are targeting our personnel count at five percent below our originally budgeted

levels; And given a smaller capex budget this year, we’ve already reduced our U.S. project

contractor group by half, to some 250 people. These actions should alone result in cash savings in 2009 of more than $50 million – a combination of operating and capital dollars. And, of course, we’ll continue to look for other ways to reduce costs. There are a number of key points I really want you to take away from our discussion today:

First of all, Spectra Energy does have the finest asset base in the business. You’ve seen this map many times before, and it shows the scale and scope of the assets, which connect key producing basins in the U.S. and Canada with major gas consumption areas of Eastern and Southeastern U.S. and Ontario. We interconnect with substantially every major pipeline in the U.S. and Canada, and we are well positioned to take advantage of the important developing shale basins like Haynesville and Horn River. Expanding our footprint through prudently incurred capital expenditures that meet our customers’ changing needs will allow us to remain the supplier of choice for customers and the investment opportunity of choice for investors. With the unprecedented volatility we’ve seen in commodity prices over the last year, I want to remind you that the overwhelming majority of our 2009 EBIT comes from fee-based businesses,


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with less than 20 percent sensitive to commodity prices. That’s important today, so let’s take a closer look at that. These charts show the parts of our businesses that have commodity sensitivity vs. those that are primarily fixed-fee businesses. We are fortunate – and we believe our investors are, too – that more than 80 percent of our projected EBIT and more than three-quarters of our projected EBITDA comes from non-commodity sensitive businesses. Of course these percentages will change as commodity prices change, but the core of Spectra Energy’s earnings is from predictable fee-based businesses.

• This slide provides a reminder of the strong fundamentals underlying our businesses. You can see here that we have contract stability on all of our U.S. pipelines with average contract terms from four to 20 years. As the contracts on our U.S. pipelines expire, we see renewal rates approaching 99 percent. We also have a favorable regulatory environment at Union Gas. The business operates under an incentive rate mechanism, which goes through 2012. In addition, Union’s ex-franchise storage services are provided at market-based rates, with the profits being phased in through 2010, which is obviously a benefit. About 30 percent of Western Canada’s earnings come from BC Pipeline, which provides low-risk steady rate-regulated revenues. Another 50 percent comes from the fee-based gathering and processing assets. And the final 20 percent comes from our Empress facility. Except for at Empress, the gathering and processing business in Canada has no direct commodity exposure, but is operated on a fee-based service. It is also important to note that over 80 percent of Spectra’s customers are investment-grade entities; and another 15% of our exposures are secured with collateral.

To further highlight the stability of the U.S. Transmission’s revenue, we have shown here the breakdown of firm vs. interruptible or other revenue on our U.S. pipelines for the 12 months ending December 31, 2008. As you can see, well over 90 percent of our pipeline revenue is from demand charges, which the customers pay to reserve capacity. The revenue is not sensitive to throughput variations or short-term economic turmoil. Another key takeaway I want to leave you with is that Spectra Energy has the liquidity to support our 2009 needs. Our liquidity is underpinned by four separate credit facilities, aggregating about $2.6 billion. We began 2009 with an estimated available liquidity of about $1.4 billion – and expect to end the year with about $1.6 billion of available liquidity.


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We will continue to exercise prudent financial decision-making and take the actions required to ensure our balance sheet remains flexible for the long term. We began 2009 with less debt than we expected a year ago, and we reduced our capex spending for the year. Both of those factors will help us maintain our financial flexibility. I’ve mentioned what we’re doing to manage costs in 2009. This will continue to be an area of focus for us going forward. And finally, we’re confident that markets will recover, and when they do we’ll be ready to quickly re-engage our delayed projects – and take advantage of additional opportunities. Let me turn now to the growth capex projects we expect to place into service this year. We expect approximately $650 million of major projects coming into service by year-end. These projects will deliver $35 million of EBIT in 2009 and an incremental $45 million of EBIT in 2010 for a total annual EBIT contribution of $80 million. Returns on capital employed in these projects will be a little above our 10 to 12 percent targeted return.

So what does that mean for the longer-term – for 2010 and beyond? Well, our more modest capex plan in 2009 means that some of our originally scheduled projects for 2010 and 2011 will be deferred, but the longer-term demand for pipeline, gathering and storage projects continues to be robust. This slide shows in further detail the projects we are working on, and those we will be ready to move forward with as negotiations with our customers are completed. As always, we will keep sharing our details on these plans as they firm up. While our level of 2009 capex has been reduced, we haven’t taken our eye off the end-goal of creating shareholder value by investing in vital and necessary energy infrastructure projects in the long term. Between 2007 and 2009, we will have placed into service more than $3 billion in expansion projects, which will contribute annual EBIT of $380 million, for a combined return on capital greater than 12 percent. That track record should give you a healthy level of optimism about Spectra Energy’s future. We remain open to new opportunities and transactions that align with our business model and serve our investors. We’ll step out, but we won’t stray too far from our home base. We’re


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investing in energy infrastructure in areas we know well, and there are great opportunities, even in the current environment. In every region we serve, we’re working with customers on critically needed expansion projects:

• In the Northeast U.S., customers on both ends of our pipeline recognize Spectra Energy as a preferred conduit.

• We are helping Northeast customers access growing supply sources, and we’re connecting suppliers with premium Northeast consuming markets.

• We’re seeing real results from producers in the Marcellus shale region. Our existing infrastructure cuts right through Marcellus on its way to high-demand Northeast markets.

• Southern Appalachian production continues to grow – seeking incremental capacity on our East Tennessee system into the Southeast markets.

• And at Union Gas, we’re continuing to pursue unregulated gas storage additions – and the opportunities and projects that accompany increased storage.

• In Western Canada, our assets are strategically positioned for growth in the conventional and tight shale resource plays. Both the Montney and the Horn River basins enjoy close proximity to our Fort St. John and Fort Nelson infrastructure. Predictions are that Horn River will be every bit as prolific as the Barnett Shale – if not more so.

• We have eight existing plants for acid gas reinjection and carbon capture and sequestration in Western Canada, and received support for future projects, along those lines, from various governments.

Whether it’s for Rockies supply arriving at Clarington, Marcellus shale in Appalachia, exciting new production from Canadian basins, or from the three – soon to be four! – LNG terminals in the Northeast, suppliers and customers alike are looking to us for their solutions. Spectra Energy is headed in the right direction and you can continue to expect that we will invest in solid returning natural gas infrastructure projects both in Canada and the U.S. And we will use our financial position and continuing access to capital markets to take advantage of opportunities we expect to see in our core business areas. With that, I’m going to turn things over to Pat, who will brief you on our fourth quarter and year-end 2008 results and give you some more details on our 2009 plan. Pat Reddy Thank you, Greg. It’s wonderful to be here this morning – both at Spectra Energy and with you today.


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As you’ve seen in our earnings release, Spectra Energy reported fourth quarter net income of $171 million, or 28 cents per diluted share. After removing the effect of special items and discontinued operations, ongoing earnings were $197 million, or 32 cents per share. For the year, we delivered ongoing earnings of $1.14 billion, or $1.83 per share, compared with $965 million, or $1.52, in the prior year. The annual results reflect strong earnings and sound operating performance from all of our underlying businesses. The company benefited from expansion projects placed into service in both 2007 and 2008 and from higher commodity prices during the year. Let’s review the results for each business segment in a little more detail. Let’s start with U.S. Transmission, which reported fourth quarter ongoing EBIT of $205 million, before the effect of the Islander East impairment, compared with $221 million in the fourth quarter of 2007. The segment benefited from higher EBIT from business expansion projects placed in service during the 2008 period. These earnings were more than offset by lower processing revenues, resulting from lower volumes and prices, and higher development costs associated with ongoing pipeline and storage expansion projects. Year-end ongoing EBIT for U.S. Transmission was $861 million, compared with $894 million in 2007. 2009 is off to a great start, with most of our U.S. pipelines and storage facilities experiencing record peak days in January. East Tennessee, Gulfstream and Egan all hit new peak delivery days during the month. Texas Eastern’s top two delivery days occurred this winter, and six of Algonquin’s top 10 delivery days occurred this winter as well. The new infrastructure we’ve put into place over the last two years is definitely needed, and the record-setting usage we’re experiencing underscores that the need continues. Now let me turn to our Distribution business, Union Gas. Distribution reported fourth quarter 2008 EBIT of $90 million, compared with $84 million in the fourth quarter 2007. These results reflect the continued increase in storage and transportation revenues, lower operating costs and increased customer usage as a result of weather that was 13 percent colder than last year. These improvements were partially offset by a lower Canadian dollar and earnings sharing with customers related to the incentive regulation framework implemented in 2008. Year-end EBIT for Distribution was $353 million, compared with $322 million in 2007.


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Union Gas is off to a strong start this year. Ontario experienced a very cold January – some 25 percent colder than a year ago. Last month, we saw record send-out from Dawn/Trafalgar, and also set a new record for storage withdrawal. Let’s turn now to our Western Canadian operations. Western Canada Transmission & Processing reported fourth quarter 2008 EBIT of $65 million, compared with $141 million in the fourth quarter 2007. The decrease resulted primarily from lower frac spreads at the Empress operations and a lower Canadian dollar. Year-end EBIT for the segment was $398 million, compared with $359 million in 2007. This winter, our Western Canadian operations have benefited from extreme winter temperatures and increased demand. Our BC Pipeline’s top 4 delivery days and 14 of the top 25 days occurred in December with deliveries well above contracted capacity. Our gathering and processing assets experienced exceptionally high levels of throughput as well. Now let me turn to Field Services. Our Field Services business segment, which represents Spectra Energy’s 50 percent interest in DCP Midstream, reported fourth quarter ongoing 2008 EBIT of $69 million, compared with $195 million in fourth quarter 2007. The decrease was primarily driven by lower NGL prices, which correlate to lower crude oil prices. Crude oil averaged $59 per barrel in the fourth quarter of 2008 versus $91 per barrel during the same period in 2007. In addition, the NGL to crude oil relationship also decreased quarter over quarter, from 65 percent to 46 percent. The decrease in fourth quarter 2008 results was partially offset by non-cash mark-to-market gains compared with mark-to-market losses in the fourth quarter of 2007, both from hedges used to protect distributable cash flow at DCP Midstream’s master limited partnership. For the quarter, DCP Midstream paid distributions of $105 million to Spectra Energy. Year-end reported ongoing EBIT for Field Services was $716 million, compared with $549 million in 2007. Now let us turn to “Other”, which is primarily comprised of our corporate costs. "Other" reported net costs of $21 million in the fourth quarter of 2008, compared with $56 million reported in the fourth quarter of 2007. Excluding special items in 2007, net corporate costs were $28 million lower in the fourth quarter of 2008. As you’ll see in a few minutes when I review 2009, our run-rate for corporate costs is in the $85 to $90 million range. Year-end ongoing net costs for "Other" were $78 million, compared with $89 million in 2007. Our next slide shows several important additional items.


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Interest expense was $166 million for both the 2008 and 2007 fourth quarters. Interest on higher debt balances in 2008 was offset by lower interest rates and the effects of a lower Canadian dollar. For the 2008 quarter, Spectra Energy’s effective tax rate was 20 percent, compared with 31 percent in the prior year quarter. The lower tax rate this quarter was primarily due to favorable adjustments in 2008 for final 2007 tax returns and lower 2008 state income tax. The full-year tax rate for 2008 was about 31 percent. As of December 31, 2008, our debt to total capitalization relationship stood at almost 62 percent – a couple of percentage points above our comfort level. Because substantially all of our goodwill relates to our Canadian subsidiaries, a lower Canadian dollar increased our debt to total cap ratio at year-end. When the Canadian dollar weakens, both goodwill and shareholder equity are reduced. The result is a higher debt to total cap than would have been the case had the Canadian dollar been be at parity with the U.S. dollar. As of December 31, we had total capacity under our credit facilities of $2.6 billion, and available liquidity of $1.4 billion. Finally, the Canadian currency exchange translation also had an unfavorable net after-tax effect on earnings for the fourth quarter of 2008 of about $15 million, compared with fourth quarter 2007. So, a challenging quarter, but a strong year overall. Now, let’s turn to what you are probably most interested in, our 2009 financial overview. Let’s look at the components of our 2009 plan. This chart provides projected EBIT and EBITDA detail for each of our business segments along with all the information needed to develop our EPS number. We are confident that you will see solid performance in each of our businesses this year and through 2010 and beyond. Let’s turn to the key assumptions which underlie our 2009 projections. As Greg mentioned, our $1.15 EPS target is based on $55/barrel oil, with an NGL to Crude relationship of 60 percent; $6.00 gas and a $4.75 frac spread at Empress. The Canadian dollar to U.S. dollar exchange rate is assumed at $1.20. These are assumptions, of course, and we are not attempting to forecast 2009 commodity prices, relationships or the Canadian to U.S. dollar exchange rate. I’ll discuss the sensitivities to these assumptions in a few minutes. We expect net interest expense in 2009 to be about $680 million, which reflects higher average debt balances and higher interest rates compared with last year. We will have no U.S. pension funding this year, and our Canadian pension funding will continue at about the $50 million, the same as we funded last year. As mentioned, our dividend will remain at $1 per share. We have assumed an effective tax rate of about 30 percent for the year. And in a change from past practices, we will fulfill our dividend reinvestment purchases with newly issued shares in 2009. Previously the DRIP shares


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have been purchased in the open market. In addition, we expect to issue new equity to fund our employee savings plan contributions. We would expect both of these actions to add between 3 and 4 million shares by the end of 2009, with the majority of that impact being felt in 2010. Let’s turn now to our 2009 Projected Cash Flow summary. This schedule shows our expected primary sources and uses of cash. You can see that we have total sources of cash of about $1.3 billion. We expect internally generated sources to be sufficient to fund our dividend and our maintenance capex, and to make a partial contribution to growth capital. So that leaves us with net cash requirements of just over $300 million before financing activity – more than $1 billion less than our forecasted 2008 requirements. We have assumed we will issue project financing at two of our joint venture projects, representing $600 million for our share. We have debt retirements due this year of a little more than $800 million. Only about $150 million of this is due in the first quarter, with the remaining amount coming due in the fourth quarter. While our plan assumes we will access the capital markets for the remaining $600 million, we have the capacity under our existing credit facilities to fund this requirement without doing so. That’s a noteworthy advantage to have – and one that allows us to move through 2009 with the intent of issuing debt only when we are comfortable with our leverage ratios and when the market provides attractive opportunities. Now let’s look at the commodity sensitivities we mentioned. This slide is very similar to one we presented at various times in 2008, but it has been updated for our 2009 expectations. Our largest exposure, as you know, is at DCP Midstream. The sensitivities shown here represent our 50 percent share of the sensitivities that Tom will review with you in a few minutes. The primary exposure in that business relates to natural gas liquids prices, which are correlated with oil prices. At the Spectra Energy level, we have a sensitivity of approximately $11 million in EBIT for every $1 change in crude prices for the full year. This sensitivity remains constant at all oil prices. At $55 oil, there also is a sensitivity of about $8 million of EBIT for each percentage change in the NGL to Crude relationship. This sensitivity increases or decreases as the crude oil price increases or decreases. At the Spectra Energy level, we would expect a $2.5 million EBIT variance for every 10 cent change on an annual basis in natural gas pricing. Our Empress system in Canada processes gas on a keep-whole basis, so it has exposures to changes in the frac spread. Our forecast assumes a frac spread of $4.75, and we have an annual sensitivity of about $16 million in EBIT for every 50 cent change in that frac spread, all other things being equal. Our Canadian earnings are exposed changes in the rate of exchange between the Canadian and U.S. dollars. We would expect every one cent change in the $1.20 rate we


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assumed to translate into a $3 million variation in net income – essentially the same as in 2008. This sensitivity is quoted at the net income level to give effect to the changes in EBIT, interest and Canadian taxes. I’ll reiterate that we have no hedges in place for the exposures shown here, except for the cash flow hedges at DCP Midstream Partners. Now, of course, in today’s volatile marketplace, it’s hard to put a lot of credence in commodity assumptions – no matter the source! So we’ve provided a couple examples of what we might see play out during the year – both in the event of either higher or lower commodity and FX effects. Let’s take a look now. Of course, we cannot know with certainty what commodity prices will average in 2009. So this example presents a case in which commodity prices are higher on average than our base case and one in which they are lower. The purpose of this example is not to tell you we think our earnings will come in between this range, but rather to provide a model which will allow you to test your own assumptions. The detailed computations behind these examples are included for your reference in Appendix 1 to this presentation, which is posted on our website. The next slide will show you how we get from 2008 actuals to our projected earnings in 2009. We begin with 2008 net income of $1.1 billion which equates to our ongoing $1.83 earnings per share, and then we walk it forward to our 2009 projected net income of $705 million or $1.15 per share. First, we expect projects placed into service in 2008 and 2009 to provide incremental EBIT of about $165 million. Roughly $115 million of this EBIT is from expansion projects at U.S. Transmission while the remaining $50 million is split about evenly between Distribution and Western Canada. The next bar shows a decrease of $80 million related to processing revenues at U.S. Transmission. If you recall, beginning in late 2006, Texas Eastern experienced increased processing volumes after Hurricane Katrina damaged another company’s major processing plant. This situation continued through June of last year at which time the other plant was restored to full operations. As a result, the last half of 2008 and all of 2009 reflect lower processing volumes. In addition, lower expected NGL prices in 2009 will negatively affect processing revenues. Next, interest expense net of interest income is expected to increase by $70 million [due to higher interest rates and higher average debt balances in 2009].


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The next three bars summarize the effect of commodity and currency declines on our 2009 earnings. Our 50 percent share of DCP Midstream’s earnings are expected to be $465 million lower, and Empress’ EBIT will decrease by $115 million both primarily as a result of lower commodity prices in 2009. We also expect to see an EBIT decrease of about $95 million as a result of the lower Canadian dollar. These commodity and currency items represent the significant drivers of our projected lower earnings in 2009. As you would expect, these lower pre-tax earnings and a lower effective tax rate in 2009 produce an income tax benefit of some $200 million. And finally, a benefit of $24 million from various other items takes us to net income of $705 million or $1.15 per share. Excluding commodity and currency reductions, we expect to see growth at each of our U.S. Transmission, Distribution and Western Canadian business units. Now I’d like to make a few comments about our pipeline and storage MLP, Spectra Energy Partners. Our fundamental objectives for SEP, of course, have been to provide an attractive currency for growth and to continue increasing our cash available for distribution. We have succeeded. Since the initial IPO in July of 2007, SEP’s unit price has performed relatively well, and annual distributions have increased by more than 10 percent. SEP’s steady and dependable earnings and cash flow from its pipeline and storage assets and its strong financial profile position it well for continued growth. Through its existing credit facilities, it has more than adequate liquidity to fund its organic expansion program. In a year which has been quite challenging for the MLP space generally, Spectra Energy Partners has retained a strong currency. That strength, coupled with the support of Spectra Energy, will position it well to pursue opportunities which may arise during this year. SEP will provide the detail of its 2009 financial plan during its conference call tomorrow. Finally, let’s take a look at our disciplined approach to financial management, which is a key advantage in the current environment. Just as in 2008, we are moving into 2009 with continued prudence and rigor in our financial policies and approach.

We will maintain adequate liquidity to allow us to execute our 2009 capex plan. We will only pursue those capital projects whose expected returns appropriately balance

risk and reward.


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We will be opportunistic in our approach to long-term financing, which will allow us to maintain the lowest cost of capital. This will allow us to remain competitive in providing new and expanded services to our customers. We will continue to maintain a flexible balance sheet and investment grade credit ratings.

And, we will keep all our options open for accessing the debt and equity capital markets

to be sure we are prepared to take advantage of the opportunities we expect to arise in 2009 which will provide long-term benefits to our shareholders.

I want to turn your attention now to an important component of our business, DCP Midstream, led by Tom O’Connor who will speak next. DCP Midstream is a great, must-run business; a business with historically high returns on capital employed – in excess of 20 percent. Even today, when we are experiencing lower commodity cycles, its returns remain very attractive. And with that I’ll turn the program over to Tom. Tom O’Connor Thank you, Pat, and good morning, everybody. I appreciate the opportunity to speak with you about how DCP Midstream will contribute to Spectra’s earnings in 2009. Last January when I spoke to our view of 2008, I talked about the potential for a record year of earnings and cash generation from this business. Well, as you heard earlier, we did realize our aspirations. Helped by strong commodity pricing and an exceptional year of operations, we realized earnings and cash flow well in excess of our targets. While 2009 is shaping up as a year with a lot of challenges on the commodity front, as I review the business today, please keep the following in mind:

• First, this is a must-run business. Over 75 percent of the gas produced in the U.S. and virtually all the gas produced in our key basins requires some level of treatment or conditioning.

• Second, the fundamental outlook for U.S. gas supply development remains very

favorable, and the strategic location of our assets in basins with growing supply has not changed.

• Third, this business has enjoyed strong performance during the commodity run of

the last several years – yet is still expected to deliver double digit returns in the comparatively low commodity price environment of today.


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• And finally, from a solid base, we provide Spectra Energy with an option for

significant upside when commodities return to more fundamental levels. Let me start with a review of our asset position. You have seen this map many times, but it is a good reminder of the overall scale of DCP Midstream. Our portfolio includes 53 gas processing plants and over 59,000 miles of gathering and transmission pipelines. We have a significant presence in most of the major US gas producing regions. Our asset position is unmatched in the midstream business. During 2008 we gathered and processed close to 6 Tbtu/day and produced on average 360,000 barrels of NGLs per day. Including volumes transported on our pipelines, we handled over 7 Tbtu/day. And we have several competitive advantages which contribute to our ongoing success.

• Our size provides us with numerous operational and financial levers which equal flexibility to respond to commodity volatility.

• With geographic diversity a drilling slow down that occurs in one region may be

offset by drilling in another region.

• An extensive and diverse customer base mitigates our exposure to any one company’s exploration plans.

• And, with predominantly percent of proceeds contracts, we prosper with rising

commodity values with protection from uneconomic frac spreads. In an industry which is must-run, these attributes result in consistent value delivery and a solid fundamental outlook. Let’s turn now to a brief look at our 2008 accomplishments. At the 100 percent level, our 2008 EBIT was about $1.6 billion with EBITDA of over $2 billion and net income of over $1.4 billion. We paid dividends and tax distributions of over $1.8 billion for 2008 inclusive of a $500 million special dividend. We benefited from strong commodity prices during most of 2008 with oil averaging just under $100/bbl. However, a big part of the 2008 story is the operations, which performed very well despite challenges associated with Hurricane Ike. We delivered strong mechanical reliability and BTU efficiency performance and completed a record number of well connects. We also initiated several low risk expansion projects at Midstream with our


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East Texas, Weld County and Woodford Shale initiatives. And at Partners, we completed the Michigan acquisition and are building out the Collbran system in the Piceance Basin. As we enter 2009, our focus remains on the basics of the business.

• Continuing to deliver on our operational performance goals of reliability, efficiency and cost control.

• Modest expansion around the footprint -- primarily completing the projects that

we started in 2008; and • Ensuring the continued financial strength of the company including preserving

our investment grade rating. So let’s turn to 2009 and take a look. By looking at this graph you can get a feel for the earnings power of this business. DCP Midstream has delivered very solid earnings and excellent returns over the last several years. As we look to 2009, earnings will moderate with commodity prices, but for the indicative commodity deck I will show you on the next slide, we are still expecting a return on capital employed in the mid-teens. The current macro environment has created several challenges which we will have to manage through.

• Commodity price volatility requires a near term focus on cash generation versus capital deployment opportunities.

• Drilling plans for 2009 continue to evolve and rig counts are declining. Most of

our customers are remaining flexible, entering the year with reduced capital budgets, with the ability to ramp up when prices recover.

• And demand for NGLs softened significantly in the last quarter of 2008 as a result

of both hurricane and recession impacts to the petrochemical and refining industries. This has created weakness in NGL prices, particularly ethane, although during January, the price of a composite barrel has recovered from its December low.

But for DCP Midstream, there are several positives as we enter 2009.


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• The robust drilling of 2008 should keep processing volumes strong well into 2009. As of today, volumes are holding steady; however, some softening could occur later in the year if low prices persist.

• The intense competitive pressure of the last couple of years has moderated, as

capital availability constrains new construction. This should keep our contract renewal rates high and reduce margin erosion.

• Cost inflation has eased, and we are seeing price declines in a wide range of

materials and services.

• And there will be opportunities to prudently invest within the footprint and solidify our long-term competitive position.

On balance, our strong foundation of assets and contracts ensure that we will weather the storm and prosper as commodity prices return to fundamental levels. Let’s turn now to the numbers for 2009. Please keep in mind that all numbers I show are at the 100 percent level, while Pat showed you the 50 percent impact to Spectra Energy. Consistent with Spectra’s presentation, the numbers shown here are based on an average full year crude price of $55/bbl, and a 60 percent NGL to crude relationship. This approximates a 79¢/gallon NGL price. The natural gas price for the year is assumed to be $6.00/MMBtu. Based on this price deck, EBIT is estimated at $730 million and EBITDA at $1.1 billion. Net income would be about $500 million with tax distributions and dividends at $290 million. With our contract structures, we are long natural gas liquids, natural gas, and condensate. When Pat reviewed our sensitivities with you, he showed you a consolidated crude sensitivity for our NGL and condensate exposure. I am providing the sensitivities for all three commodities. This additional detail will reduce the need to follow the NGL to crude relationship, which in the last few months has been very volatile. For example, you probably have noticed that since the first of the year, while oil traded down with significant day-to-day volatility, the value of the NGL barrel has been much less volatile. The result is that the correlation has been moving significantly during this period. Over time, we expect these relationships to come back in line with historical perspective. Sensitivities shown here represent the change to the earnings potential of the business should the price delta from actual realized prices occur for the entire year. For example, a 1¢ change in NGL pricing from 79¢/gallon, that continued for the full year, would result in an EBIT impact of about $12 million.


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For the month of January 2009, we experienced a weighted average NGL price of about 60 cents per gallon, which is up from a low point of 50 cents per gallon in December. The NGL to crude correlation in January averaged close to 60 percent, which is up from about 50 percent in December. Commodity markets remain in contango, and while we budgeted low prices to start in 2009, the expectation is that the value of an NGL barrel will continue to strengthen as we move through the year. Let’s turn now to our contract mix and margin data and show you how 2009 is shaping up. Projected volumes are slightly over 8 Tbtu/day, and gathering and processing volumes are estimated at 6.5 Tbtu/day. As expected, unit margins are down in 2009 versus 2008 with lower commodity prices, and the percent contribution from the various types of contracts has shifted accordingly. The contribution from percent of proceeds contracts with an average margin of 65 cents / MMBtu, is projected at 60 percent. The contribution from keep whole contracts with an average margin of 50 cents per MMBtu is projected at 10 percent. Fee based contracts should contribute about 15 percent of our margin in 2009, and our fee based margins are estimated at 15 cents. Other margins, which come primarily from condensate sales, NGL and gas trading and marketing should contribute about 15 percent. In conclusion, we believe this business will deliver solid operating results in 2009 and will continue to be an important part of the earnings picture for Spectra. Notwithstanding today’s weak commodity environment, this business should deliver double digit returns and enhanced earnings and cash flow as commodity prices strengthen. I hope you will agree that our focus on delivering reliable and efficient service, growth around the footprint and preserving the financial strength and flexibility of the company is really the right place to be. And with that, let me turn it back to Greg. Greg Ebel Thanks very much, Tom. I know we have provided you with a lot of information today, and no doubt that the economic front is a challenging one, and there is a lot of uncertainty and angst among market watchers and investors alike. But for Spectra, I am certain about the following:

• We will successfully manage through this current downturn in the economy. • We will pay our $1 a share for dividend. • We will continue to control our costs. • We will protect our core business – our assets, our customers, our balance

sheet, our credit standing.


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• And by doing so, we will get the opportunity to grow our earnings and create value for investors.

With an asset footprint that is frankly irreplaceable, a geographic position that serves growing markets and dependable earnings from fee-based businesses, we are well-positioned for 2009 and for ongoing growth in 2010 and beyond. I want to thank you for your continued interest, your investment in the company, and I’ll turn things back over to John so that we can take your questions. John Arensdorf Thanks Greg. Janice will now take questions. If you can get us started, please. Janice Thank you, sir. At this time, I would like to remind everyone that if you would like to ask a question, please press star, then the number 1 on your telephone key pad. We will pause for just a moment to compile the Q&A roster. Shneur Gershuni, UBS Hi. Good morning, guys. Congratulations to both of your new roles. You guys gave out a ton of details today which is great and greatly appreciated. I just wanted to ask, I guess, two kind of big picture questions—one kind of bullish, one kind of bearish. Just starting with the bearish one, given where oil and gas are kind of today, how did your capital plan for liquidity plants and so forth change with these assumptions if your lower case assumptions tend to be high come mid year and so forth? Would you be throttling back any further capex or this is a solid plan for the year end so forth? Greg Ebel From a Capex perspective, I don’t see any significant changes. As you know, when we put projects to work, they are already contracted up with a good investment grade customer, so I don’t see any change on that front. If anything, if gas prices really took off and it cranked up some of the domestic drilling that folks are pointing out how rates have been laid down, then that might crank up the interest in accelerating projects, but I don’t see a downside from that perspective. Obviously, if oil prices were lower than we expected on average for the year, that has an earnings impact out of DCP and some cash impacts. But I don’t see that changing the capex program for 2009. The real judgment call is as we go through the year, how are things going to look for 2010 and going forward?


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Shneur Gershuni Then the flip side is if the capital markets ever return, specifically for the MLP market, is it a safe assumption that we could see SEP and DPM seeing some asset dropdowns on both sides and so forth? Is that a reasonable assumption? Greg Ebel I’ll speak to SEP and maybe Tom, who’s the chairman of DPM, could speak on that front. With respect to SEP, we put that vehicle in place to grow the entire pie, and frankly, its’ currency has held up quite nicely relative to other currencies and we definitely see that as a vehicle we can use to grow the entire business as opposed to doing dropdowns. One thing I will say, obviously, we’ve indicated our desire to keep growing that business in distribution, but the first focus would be on the organic growth that it already has which is nice in the pipeline storage business. Looking at if acquisition opportunities are out there, and we think some of that consolidation in the MLP world will happen; and then last, we would look at dropdowns. Tom, maybe you want to speak to DPM a little bit. Tom O’Connor I think DPM strategy is basically consistent. We look at dropdowns as kind of a means to an end to grow the overall enterprise. Right now, they are focused on completing a couple of organic projects that they have on tap, and those are moving ahead towards completion around the mid point of this year. Then we also have announced that we will do a dropdown of 25 percent of the East Texas asset from Midstream to Partners. That is on track, and Partners will provide an update on the status of that on their earnings call here in a couple of weeks. Shneur Gershuni Great. Just one final question: Greg, when you look out to 2011, 2012, kind of where do you like to see the long-term payout ratio for the dividend? Greg Ebel As I said, I’d like to see it move back towards that 60 percent range. As I said we were considerably lower than that in 2008 and will be above that in 2009. But I think that 60 percent payout ratio would be a fair target. Now obviously, we’re growing the pipeline, the fee-based side of the business, quicker than we are any elements that have a commodity piece to it, so if that continues to occur and you get the fee-based business up to a much larger percentage, then that could moderate even higher. Shneur Gershuni Great. Thank you very much.


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John Kiani, Deutsche Bank Good morning. On slide 35, I’m trying to just to get a little bit of a better handle on the scenarios that you all showed. In the lower case scenario that gets you to the $1.01 of earnings per share for 2009, are those assumptions basically kind of the current forwards? The $45/barrel crude assumption to me looks like it’s in line with the current forwards. I was wondering, perhaps, more about the 65 percent NGL to crude relationship used in that scenario. How does that compare to current market? Greg Ebel John, they weren’t meant to imply anything. We were just trying to take five bucks up, five bucks down. I think the forward market’s pushing about $50 actually on oil right now, but that wasn’t what we were trying to do. We were just trying to show, depending on your view on where commodities are, if you are higher and lower, here’s what the results would look like. Typically, you see NGL correlations go up as oil prices go down. As Tom mentioned, in November, we saw correlations in the 40 percent range. In December, they were 50 and for January they’ve been a little bit above 60. This is just trying to show some of the historic relationships that you’ve seen. John Kiani Thank you. Then on the third quarter call, you talked briefly about the potential to update your long-term earnings per share growth rate. I know previously you had talked about 6 percent. I was wondering what you all think about that now and where you kind of stand on that. Greg Ebel You know what John? I think at this point in time, let’s see how the first part of 2009 plays out before we go there. As you know, when we were talking about that, we were saying if you assumed oil was in the 85-90 percent on a flat basis, you could see that 6 percent type of increase. That may have moderated a bit. If you took an apples-to-apples comparison of our fee-based businesses—the pipeline, storage, distribution—and you accounted there for any commodity or FX changes, we’d be seeing about a 6 percent annualized growth rate. Exactly how that’ll flow down into the EPS element, let’s see how the year progresses before we know that, given the kind of volatility you see out there. John Kiani Just one last question on the tax rate for 2009: It looks like you all are assuming 30 percent, and for 2008, looks like it was about 33 percent from an assumption perspective at the beginning of the year. Can you talk a little bit about what the change is or the benefit there?


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Pat Reddy John, the tax rate for 2008 averaged 31 percent and with lower state tax rates that were enacted during the course of 2008, we’ve ratcheted that down to 30 percent for this year. John Kiani Okay, great. Thank you. Reza Hatefi, Decade Capital Thank you very much. You mentioned a little bit your financing plans, and your debt to cap ratio, I guess, is at 62 at year end. Could there be a potential need for equity going through the year or your credit lines are going to be sufficient to meet your financing needs? Greg Ebel Well here’s how I kind of look at that: We’ll raise some equity through the DRIP plans and financing the benefit plans. We’ve got a lot of great projects that we’re out there financing, and if I thought you could take some of the volatility off the market that you see in things like currency rates and how that might move around the balance sheet, if you thought that you could access the capital markets either debt or equity, that’s something that you’d have to consider; but only if you thought you could do it obviously reasonably priced, and it would allow you to continue to grow the business. Reza Hatefi Thank you very much. Lasan Johong, RBC Capital Good morning. Thank you. Greg and Tom, I guess, have you guys spoken to the E&P companies in your operating areas and asked them what your capex plans? Greg Ebel Maybe I’ll let Tom go first on the processing side, but then we can speak to you as well a little bit. Tom O’Connor Sure. The answer is yes, we’ve had a number of conversations, and quite honestly, they vary company to company. I think most are consistent with what you're seeing in the public domain as they announce their plans here over the last month. I think the key word that I’m hearing is flexibility, trying to live within cash flow. Yes, rates are being laid down but decisions are being


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made around what are the most profitable areas for them to continue drilling. The other thing I’m hearing is maintaining the flexibility to ramp up quickly when prices recover. So those are the key themes, and we’re sticking pretty close, obviously, to them as our major customers. Greg Ebel Yes, and as we look on the pipeline side and storage and distribution side, continue to see activity in the Marcellus and the Appalachian. Obviously, it’s centralized. I’m a little bit surprised we haven’t seen some slowdown in Western Canada in the areas where we are, but the Horn River, the Montney Basin, producers continue to be working hard, and I think the really large producers obviously look at this from a long-term perspective, know that the gas is there and the value; and you're looking at longer-term development opportunities. We’ve seen some slowdown obviously, but perhaps not as much that you’re seeing in some other areas. Lasan Johong Let me ask you a “what if” question. What if capital budgets come down by another 30 percent in the second half of the year? And let’s say that your low case gas price scenario is roughly correct, and oil prices stay around the same numbers or gas prices fall even further than that scenario, 550. Where do the numbers go? Does that not then change your thinking on what you would spend on capex as well? Greg Ebel Again, two ways to look at it. Obviously, in the majority part of the business, the fee-based part of the business, a short-term change in gas prices is not going to affect the capital we put to work on what our long-term assets that we put in the ground for 30, 40, 50 years. So when we look at gas, we kind of see it in that $5-7 range from a long-term perspective. We don’t put that steel in the ground, if you will, until we’ve got signed up contracts. I don’t think that has an impact on our capital plans for this year. I think what it does, if it was significantly below that for a sustained period, what does that mean for longer-term opportunities? So that’s something we’ll be watching closely. Tom, would you provide your perspective? Tom O’Connor I’d say a couple of things. First of all, our capital budget is pretty modest, and as we spend capital, we watch the development and are lined up pretty closely with our producers in terms of what we see their rig activity and volume growth. In general, our capital heading into this year is pretty modest and down significantly from last year. The other thing I would note is that although prices have come off, a number of producers are still saying they will have volume increases this year. That’s something I think we’ve got to factor into how we think about overall our capital deployment.


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Lasan Johong So then it’s fair to say that you guys don’t think there’s any impact from LNG in the next year or two? Greg Ebel Well I think your trigger point for that, Lasan is that we watch LNG closely, and as you know, there’s been a lot of different view over the last three years -- it’s coming, it’s not coming. If you look, there’s a lot of liquefaction coming on offshore North America later this year. That gas has got to go somewhere. So that could definitely come to North America or it can go to Europe. I think we will have some interesting views on that as you move into the last half of the year, and that liquefaction comes on. We’ve got gasification abilities here and definitely on the East Coast. You see our plant that went into service late in 2007, and obviously Phase 4 on Maritimes is very much tied to Repsol’s plant, so we’ll see. That could lead to both pipeline and storage opportunities. Our East to West project is very much designed around LNG producers and their desire to get their gas to market. Lasan Johong That would have pretty devastating effects on DCP Midstream, would it not? Greg Ebel No, I don’t believe so. Why would you say that? In terms of lower gas prices overall? Lasan Johong Yeah, and E&P will probably cut the capex budget by at least another 20 or 30 percent. At 4.50 gas, hardly anything in the U.S. that’s economic all in costs. Tom O’Connor To me that’s a bit of a draconian scenario. If you look back over the last couple of years, we’ve gone back and forth on the expectations of LNG imports, as Greg has said. Now we’ve also experienced over the last three to five years significant growth in domestic production. My expectation is that the market continues to grow; domestic production will compete with LNG; and the supplies will move to the market from both sources. From DCP standpoint, if you look at our diversity of the number of basins that we operate in, most of those basins have been producing gas for years, and we would expect that to continue. A key element of all of this is the growth in the market, and we’ve continued to experience growth in the market. Carl Kirst, BMO Capital


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Good morning, everybody. Congratulations, Pat, since I haven’t spoken to you in many years. A couple of questions: First, maybe I could start off with a fourth-quarter question. I just wanted to delve into the U.S. Transmission number a little bit more and make sure I understand what the deltas were year over year, both on the processing dynamic as well as the higher development costs. In part, I want to be clear that—is this processing dynamic—are you saying that you’ve had some lower throughput through your system or is this from straddle plants on the pipes themselves? Pat Reddy On the processing side, it was specifically related to the one plant that Greg talked about that had higher throughput as a result of hurricane-produced outages at another pipeline’s plant, and that began to trail off at the middle of last year. So that really is the impact for U.S. Transmission. Greg Ebel It’s a combination of the two in terms of another plant being down and us getting more volume as opposed to Rita and Katrina. As that other plant came back up, we obviously lose those volumes. Obviously, you’ve got a delta there on NGL prices as well. There’s probably about $25 million that impacts. Carl Kirst From the combined plant plus the lower NGL prices? Greg Ebel Yes, correct, versus Q407. Carl Kirst Appreciate it. Sort of sticking with processing, maybe going over to DCP, Tom, I don't know if I’m looking at apples and apples numbers, so if you could help me clarify. I’m looking at what was, I guess, on slide 44. You’ve got volume gathered and processed of 6-1/2 Ts and total through put of 8.1 for 2009. That seems to be sort of 10 to15 percent higher than what was done for 2008, if I have those numbers correct. I think that was listed on page 40. With your stance of, hey, we could see some volume softening depending on what prices do, is 2009 actually modeling up to volume increase right now? Tom O’Connor Yes, we are showing some volume increase, but what you need to account for there, Carl, is we did add some assets during 2008. Remember, this is a consolidated view which includes Partners in it; in particular, the larger asset that we add was Michigan. So that contributes to that number


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increase. Then we expect to see some modest increases around the system in some of our specific areas. We have included asset adds in that number. Carl Kirst How do you think that translated into as far as growth and liquids produced? Are you looking for something in kind of a similar 10 percent gain, as well? Tom O’Connor No, I think liquids were probably around five percent or so, and also one of the other things you need to account for in the 2008 numbers is we got clipped by the hurricane pretty good there. So those numbers reflect some volume losses associated with hurricane in 2008 as well liquids losses associated with the hurricane in 2008. Carl Kirst Fair point. Pat, just one question going back to the tax issue. Do you think that this 30 percent level can be sustained beyond 2009? Pat Reddy We’ve looked at 2009 and 2010, and I think that 30 to 31 percent is sustainable. Greg Ebel Here’s the factor there that’s going on there, Carl. We’ve got a bigger proportion of our earnings coming out of Canada right now given less coming out of DCP, and you’ve got lower corporate tax rates in Canada, as you may be aware. So we’re getting some of that benefit, so it’s a little bit variable. Obviously, if commodity prices came back strong, you’d see it reversed to more U.S.-based earnings. That’s the accelerator or decelerator, if you will. Carl Kirst Okay, appreciate the clarification. That’s it, thank you. Keith Larose, Bradley, Foster & Sargent, Inc. Good morning. It’s Larose, L-a-r-o-s-e, just for the record. Eighty percent investment grade clients, I think you mentioned. In today’s environment in going forward, that really doesn’t help you very much. Can you give more color on the layers of your customers and some of the concerns you may or may not have within the customer base? Greg Ebel


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Sure. When you think about the northeast and the southeast, maybe that’s a way to look at it. You're talking about the folks like FPL. You're talking about National Grid. You're talking about major PSEG, etc, major LDCs that are really off takers of our services. On the producer side, the big guys would include guys like EnCana, folks like BP. If you looked at the U.S. portfolio, about half of them would be “A” or higher in terms of our exposure. Hopefully, that gives you a little bit of insight, but generally speaking, we don’t have a lot of financial players, since we don’t have a trading operation. Some of that capacity would be held by some of the trading operations but pretty minor, so you're talking about largely big producers and largely big LDCs. Keith Larose Are you seeing any customers with current problems? Greg Ebel No, we have not. When the havoc was hitting the Wall Street in late third quarter/early fourth quarter, we did see some exposure there we were concerned about, but largely that’s been either collateralized or they’ve sold those positions to other players. Even at Union Gas where we have a large retail operation, we have not seen an increase in bad debt, for example. They were obviously recovered in rates for that, but nonetheless, it’s the kind of thing you watch for and we have not seen that happen to date. Keith Larose What on the cost to capital side for debt are you assuming 2009? Pat Reddy As we look at credit spreads and treasury rates, it’s about 8.25 percent for issuances as Spectra Energy capital. Keith Larose Then one more question on the pension side—what’s your return assumption? Female Speaker A little bit over seven percent. Pat Reddy It’s slightly over seven percent for our long-term return. Keith Larose


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Okay, thank you so much. Matthew Akman, Macquarie Thanks very much. Couple of questions for Tom on the DCP Midstream. I guess, first of all, why would the return on capital be lower in 2009 than 2005, given the crude oil price assumption is similar? Tom O’Connor Matthew, what you're seeing is what happens as we renegotiate contracts over time. They come up. They may be set at a particular sharing and then as prices move, those contracts get renegotiated, and that’s probably what contributes to most of that change. Greg Ebel Matt, we had a lot keep whole as I recall going back to those times, too, which as you know we’ve moved away from that for the right reasons given the risk parameters of keep whole contracts. You go to more percent of proceeds type return. Matthew Akman This chart, Tom, correct me if I’m wrong, would this be EBIT on capital employed? Tom O’Connor Yes, it is. Matthew Akman So that implies capital employed in this business of maybe $5-6 billion. Is that right? Tom O’Connor About $5 billion. Matthew Akman Why is that number so low? With 59,000 miles of pipes in 53 plants, is that just depreciation of those assets over time? Because the replacement value of those would be much, much higher than that. Tom O’Connor It would be -- you're exactly correct. Over the years, we’ve pretty much tried to live within our depreciation, so we’ve not been building capital employed significantly over the years.


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Matthew Akman I guess I’m trying to get to the fundamentals of how the business model—if now at today’s oil price you're going to be earning a suboptimal return on capital in that business, maybe at $55 oil you could argue it’s approximately correct, I guess, sort of low mid double digits. But at today’s oil prices lower and yet, as you said, this is a must-run business. The U.S. gas business cannot exist without this business. So is this the right business model because it would be awful for a business that big and that necessary to earn a suboptimal return for a period of years if we’re in a multi-year recession. Is there something you should be looking at in the business model to stabilize this? Tom O’Connor Well I think what you have to look at, and we tried to illustrate through this chart, is that the returns have been anything but suboptimal over the last several years. What this business has the flexibility to do is reset contracts as it moves forward if we’re not happy with the returns and not happy with the returns we would need to continue to invest in the business. What we’re illustrating here is that even in a year of challenging commodity prices, we still expect to see returns in the mid teens. And obviously, as prices correct and recover, we would expect those returns also to trend positively north. Matthew Akman Though you don’t see really any changes to the business model. You're happy with the way the contracts work and the way the business makes money today? Tom O’Connor I think as we look at it today, we’re pretty much aligned with our customers, and my belief is that is always a good equation. Now don’t forget: on these contracts, and we haven’t talked a lot about this, you do have minimums in them, so that if, for example, volumes came down, minimums might kick in. If prices came down, minimums might start to kick in. So there is a floor to these things. Then if you were in a sustained period of low commodities and became concerned about a particular area or particular basin, we always have the ability to start negotiating fee-type contracts for the business. It’s not been where we’ve been. We’ve prospered over the years with the setup that we’ve had. As Greg mentioned, we have moved from significant keep whole to more POPs. That’s worked for us. As this chart shows, it’s worked very well over the last several years. Unless we see a dramatic change and believe that there would be a dramatic change in the business, then I think we’ve pretty comfortable with where we are. Matthew Akman


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My last question is maybe a bit of a statement, but it’s that; there’s a lot of very pessimistic views out there on oil right now, and I think people want to get comfortable that you will not operate this business at any kind of a loss or anything really close to that. Tom O’Connor I think you can get comfortable with that. Matthew Akman Thanks, those are my questions. Leslie Rich, Columbia Management I wondered if you could walk through your financing plans in a bit more detail. You said that you would be free cash flow negative by $300 million or so and then that you had $800 million of maturities. I missed what you said about how you plan to address that. Pat Reddy We do have refinancing primarily in the fourth quarter of about $625 million, call it, that comes due. That’s kind of the normal course of our long-term debt, refinancing. We have a couple of project financings that we have on the table to pursue this year, but that’s basically to repay ourselves for outlays that have already been made in prior period. So with respect to newer incremental financing, it’s fairly modest for the year. Leslie Rich So the $310 million negative free cash flow—I’m just trying to understand if you're doing $800 million of re-financings plus $300 million of new financings or some of that— Pat Reddy Yes. That’s about the order of magnitude. Leslie Rich Okay, so a total of 1.1. Pat Reddy Yes. Leslie Rich Okay, thank you.


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Nathan Judge, Atlantic Equities Good morning. I wanted to ask a question to Tom with regard to M&A and the DCP Midstream. The company has had a long history of waiting until prices for midstream have fallen and looking at them and across industry. Is that an option right now, and how is that all paying out? Is that even an objective of the company? Tom O’Connor I think you rightly pointed out that the history of the company is one where it has been built over the years taking advantage of the need for consolidation in the industry to drive efficiencies and deploy capital effectively. That is the history. I think we obviously continue to evaluate those types of opportunities. My own belief is that there’s quite a bit of—the industry is quite fractionated, and I would expect that as things go forward, you're going to see some consolidation. Obviously, we’re interested in continuing to grow the company and grow the enterprise. We do have the MLP and that has been a focus of the MLP over the last couple of years. Right now, I would say that they are very much focused on their organic projects in getting those complete, but we have that available to us, and it is my belief that there will be some consolidation here as we go forward. Nathan Judge Just with regard to the comments on the gas transmission business in as far as delays of capital, I found that interesting given the amount of flexibility there appeared to be. I just wanted some more color. Obviously, you said in your comments that you are approached by customers in providing that delay in expansion of capex, but going forward, how much flexibility does Spectra have in approaching clients and customers building new pipes to renegotiate perhaps delay and how does that actually work out who would be—how much flexibility do you have in 2010, 2011, etc. Greg Ebel As you know, Nathan, it usually takes us anywhere from 18 to 24, sometimes 30, months to bring projects to fruition. So until you’ve got FERC approvals, etcetera, there’s always an opportunity to reopen issues. I’m not expecting to have to do that. The 2009 projects, the Maritimes Phase 5, EnCana, a big producer, was looking at opportunities that they had moved forward with us. We had had various approvals to go forward, but when a customer indicates that they're perhaps having a new challenge with a project, we look at this from a long-term relationship perspective. Nicky is making sure that we weren’t disadvantaged financially, at least kept whole financially, and we were able to do that. The other key one for 2009 and is really just being spread out is East to West, and that’s an LNG-related project. We had a little chat earlier in this phone call about some of the volatilities and movement on people’s views as


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to whether LNG comes in or not, so again, that was in discussion with customers. So I think there’s some room on the 2010 and 2011 projects given that the stage that they're in. It depends on projects where we are, again, with regulatory approvals and with contractual approvals. Nathan Judge Given large projects seem to have at least you’ve mentioned about less interest from customers on providing new large projects, do you see that the potential for continuing elongated, higher-growth rate is perhaps more challenging today than it has been? Greg Ebel I think everything’s more challenging today, Nathan. With the uncertainty that’s out there from top to bottom in the economy, I think that really super-large projects create some real challenges both for customers and for those providing the service. Not to say we wouldn’t do very large projects, we’ve really focused on relatively modest-sized projects. The Southeast Supply Header project was around the largest project we did last year at $600 million, but most of our projects are, call it, $200-400 million. I think that gives you some more flexibility both with customers and yourselves in terms of making decisions. And I think it leads to less opportunity for big surprises. For example, we’ve seen some of the very large projects be very expensive to come in. When you're halfway through some of those types of project, and you run into some economic challenges unforeseen by virtually everybody that we’ve seen go on this year, that’s a tough place to be. Most of our projects, once we start, we’re getting it done in 12 months, and again, they're not multibillion dollar projects. Again, in the right scenario, that might be what you would do, but I think those projects would be tougher to pursue in the current environment. Nathan Judge Just lastly, obviously the dividend payout ratio has come up as a question earlier. Could you just run though your options as far as being able, in your determination, to stay in that level of dividend if perhaps your lower price environment scenario were to exist in the dollar earnings per share payout ratio. And what are your options going forward if that scenario persists for the next several years? Greg Ebel I think the key thing is to look at—our EBITDA in 2009 about, $2.6 billion so when you bring that down to earnings after tax excluding DDA and stuff, you're talking about close to a billion dollars or $960 million dividends around 600, so you're 1-1/2 times, 156 percent, of SET EBITDA if you’ll look at it that way. Obviously, we bring in cash that more than covers our maintenance. It makes the contributions Pat made to expansion capital and then pay the dividends. Obviously, you could pull back on some of the expansion capital. But again, we see


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the growth opportunities allowing that fee-based business, both in Canada and the United States, to continue to grow and therefore supporting the dividend. About 85-90 percent of what we earn today is supported by those fee-based businesses—supports the dividend. Nathan Judge That’s very helpful. Thank you. Becca Followill, Tudor Pickering Holt Good morning. Thank you guys for all of this time. Clarification on some of the questions that have already been asked. On the, I think it’s a $200 million, reduction capex, is it all related to Islander East and AGT East or West?. Greg Ebel No, again, we had kind of given some indications of being in the $800 million range, and it’s going to $500 in expansion capital so that’s $300 million reduction, Becca. Islander East wasn’t a big factor because that’s been in the works for a long time, and we weren’t really spending any new dollars on that. It’s largely related to the East to West project and the re-scoping and changing of that project as well as the Maritimes Phase V expansion that was related to EnCana, which I think was around a $350 million project, much of which would have been spent this year. So there are some other little nips but those are the big drivers there. Becca Followill Then on pipes, the delta between 2008 and 2009, I think you said 25 million is due to just some up tick you got because of volumes being temporarily diverted, but I still would have expected it to be higher. What else, just given the number of expansions that you put in 2008 and in 2009, what else is acting as a reduction in there? Greg Ebel Processing is a piece of that. That’s about an $80 million negative year over year for the plant outage that we talked about earlier, Becca. Becca Followill Okay. Then on the midstream side of the business, DCP Midstream, excluding the hurricane impacts where you get a pickup in 2009 and excluding the acquisitions that were made in 2008, are you looking for volumes to be up or flat or down in 2009—excluding the noise? Tom O’Connor


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I would say volumes would be slightly up in 2009. A lot of that driven by the fact that we saw rig counts in most of our areas actually peak late third quarter/fourth quarter. We’re still actually hooking up some of that gas. So we come into the year and we did have a record year well connects in 2008. So we come into the year with a bit of a tailwind on volume. Becca Followill Great. Thank you. Rick Gross, Barclays Capital Good morning. Couple of topics: First is that at Union Gas, you guys are early on in the PBR, and maybe you can either help me with—incrementally, you reset the rates, you reset your returns what you expect to be able to improve on that by the time you get to 2012. Then the other question for Union would be, with all of these record send outs you articulated at Union Trafalgar—your two northeastern pipelines—what are the prospects for a sizeable storage project coming out of that? Greg Ebel On the first thing you’re right. We just finished the first year on PBR, and they set the rate for the ROE at about 8.5 percent. So those rates get set every year, and then there’s a productivity factor that goes in. You’ll net the up a little bit in terms of rates, and then you lose in the productivity factor. The way the deal works is that you could earn up to 200 basis points above that ROE, then you chair after that, and then there’s an off ramp if you are above 300 basis points. That’s the way it would work. You can see that, I think, on an apples-to-apples basis, Union grew at about 6 percent in 2008, and you see a similar again on apples-to-apples basis in 2009. Obviously, there are a couple of drivers there. On the positive side, we have put three new Dawn Trafalgar expansions in over the last three years, I believe. Storage opportunities probably even more important than PBR, Rick, as about a third of our storage up there moves at already market-based rates, but used to provide that feedback back to retail customers. Instead, that’s now going to the benefit of investors, so that’s where I see the opportunities there. So through 2012, I’d expect you to see pretty nice growth, probably a little bit more than what you’d see from a typical LDC, which as you know, Union was the storage, and 5 bcf/day pipeline is not your typical LDC. We’re looking at storage opportunities up there. I think on some of the slides we give, there are some projects there on the storage front. Beyond just size though, it’s also deliverability. As you move more and more into gas-fired generation throughout the northeast and in Ontario, deliverability becomes really important because as you know, the power market and the gas market work in two different fashions, and you need quick deliverability. That provides opportunities. Then obviously, sure, we keep seeing peak days on the pipe that we have, and one thing you can’t do as an LDC is not have your gas available on the cold days in the


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winter, so as we see top 10, top 20 peak days, I’m hopeful that customers will see the opportunity and the need to continue building out those pipelines. And I want to make sure we’re positioned to take advantage of those. It may not come in 2009, but I think they’ll be there going forward. Rick Gross Somebody asked the DCP M&A question, but I’ll ask it in a slightly different way because they have been very aggressive in all the downturns. I noticed in the net income versus distribution piece, the relationship went from a record year special payout to paying out materially less than the net income in this coming year, and I was curious as to whether that said anything about collecting capital, getting ready to do something or conversely whether you're a little short of debt capacity there in case you might want to do something. So maybe Tom could flesh out what your debt capacity is to make an acquisition at DCP and why you're operating with the distribution below net income. Tom O’Connor As far as the payment of the dividends and tax distributions that basically reflects the formula that we have in place, at the LLC, which is either 90 percent of net income or 75 percent of cash flow. Of course, the board always has the ability to look at that and decide what’s optimum for the company as well as the responses in terms of what they're willing to pay out. To your question around M&A activity, I think, as I said earlier, it’s something that we’ll evaluate as we go forward. The company’s always been pretty opportunistic about M&A activity, and the sponsors have been very supportive. We have a couple of places, obviously, where that could take place, either at the LLC or at Partners. Over the last year to two years, hopefully, what you’ve seen also at the company is that we are focused on our organic projects, and as we talked earlier around the middle part of 2008, we laid out several organic projects that we had on the table. We continue to pursue those. Those are very high return projects, so where we’re trying to get the company to is a place where yes, it’s opportunistic around M&A, but it’s also very good executer of organic projects because those are some of the best returns I can see. Rick Gross You alluded to contracts and rollover of contracts. Couple of question in that regard: Part of that margin deterioration, we’ll call it, historical legacy of probably some real old, very, very high margin POL, POP contracts. I guess, first of all, what percentage of your gross margin is still what we would call real old line, kind of out of the money types of things? The other piece of it is, as these things mature, what percent of your gross margin typically rolls over every year in this contract renegotiation?


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Tom O’Connor In terms of rollovers, if you put our contracts into buckets, you're probably dealing with about a third of our contracts coming up every year for renewal. Some of those are renegotiated, some go right into evergreen, and they just continue to produce at the originally negotiated sharing. But about a third of those turn over every year. Which really is where we spend a lot of time is on some of the larger, more aggregated contracts that come up every year that have significant volumes associated with those. Those can be subject to change. If you look at year over year, again, about a third of our volume comes up. A portion of that goes into evergreen, a portion gets renegotiated. We probably see a couple of percent gross margin degradation year in and year out from renegotiations. Now the other thing I’d mention, Rick, is of course in a hundred dollar oil environment, that’s a very different number from, say, where we are today. And as I mentioned in my points, we would expect less of that to be occurring in today’s environment as we look out and say this is what we need to process the gas versus, say, sharing arrangement may be changing more so in a hundred dollar oil environment. Rick Gross Okay, great. I’ll just maybe add one observation. You’ve gotten a lot of questions about dividend payment. I thought it might be handy to provide debt income from your just fee-based businesses. You’ve shown it kind of in a contract structure and in kind of a percent of EBIT and all of those kind of things, but if you just kind of took all your fee basis down to net income, you would probably show a very significant portion of your net income as coming from that fee-based stuff. Greg Ebel It’s just about a dollar. It’s a little hard to do directly because as you know, we don’t raise the debt specifically to each one of those businesses, Rick. Rick Gross That’s fine. I understand the issue. Greg Ebel Fair point, though. Jim Harmon I’m in your queue somewhere, but I thought I’d jump in and you can take me out. Two quick questions: How much interest did you capitalize in 2008 and what’s your expectation for 2009 and how do we think about that line item going forward?


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Pat Reddy Hi, Jim, this is Pat. In 2008, we capitalized debt AFUDC of about $25 million at Spectra Energy Transmission, excluding Gulfstream and SESH and equity AFUDC of about $33 million, so about $88 million in total. For 2009, I don’t have that broken out from our budget. Let me think about that for a minute, Jim. Greg Ebel It’s probably in the $40 million range because obviously we got a lot less capex. I’m trying to go back and think. In 2007, that’s about what we would have spent, Jim. Obviously, that’s going to move up and down depending on the Capex number. Pat Reddy It was $40 million in 2007; that’s correct. Jim Harmon Okay, great. The second question is can you quantify what the year over year swing was in processing at the transmission subsidiary. I don't know if you can do it on the quarter on quarter basis or full year or both. Greg Ebel Year on year is about $80 million so it’s a combination of some volume and some prices. Jim Harmon Other than that, it gives you some upside on occasion. Why not renegotiate that out of that straddle plant? Greg Ebel It’s part of the business. I guess that’s something we could look at, but there’d be a variety of customers to date. It’s not typically the type of swing you would see, Rick. I think the volatility you're seeing in the last year or 18 months has been extraordinary. I wouldn’t typically expect it to be a significant difference. John Arensdorf Operator, that’s all the time we have for questions today. I’d like to thank everyone for joining us on the call today. If you do have any additional questions, feel free to give either me or Patti Fitzpatrick a call, and we’ll try to get the questions answered.

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