spectra energy 2Q2007Transcript

Spectra Energy
Second Quarter Earnings Review
Conference Call Transcript
August 6, 2007

O: I would now like to turn the call over to John Arensdorf, Vice-President of Investor
Relations.

JA: Good morning and welcome to Spectra Energy’s Second Quarter 2007 Earnings Review.
Thank you for joining us today. Leading our discussion today will be Fred Fowler, our
President and Chief Executive Officer and Greg Ebel, our Chief Financial Officer. Also
available to take your questions at the end of the call are Martha Wyrsch, President and
CEO of Spectra Energy Transmission and Sabra Harrington, our Vice-President and
Controller. Fred will begin our discussion today by sharing his perspective on our results
for the 2nd quarter. Greg will then provide more detail and context around Spectra
Energy’s results and those of each of our business segments. Fred will close by updating
you on some of our key capital projects, and then we’ll open the lines for your questions.
Before we begin, let me take a moment to remind you that some of the things we will
discuss today concern future company performance and include forward-looking
statements within the meaning of the securities laws. Actual results may materially differ
from those discussed in these forward-looking statements. You should refer to the
additional information contained in Spectra Energy’s Form 10K and our other SEC
filings concerning factors that could cause these results to be different than contemplated
in today’s discussion. And in addition today’s discussion includes certain non-gap
financial measures as defined by SEC Reg. G. A reconciliation of those measures to the
most directly comparable gap measures is available on our Investor Relations website at
www.spectraenergy.com. And with that I’ll turn the call over to Fred.

Thanks John. Good morning everyone. We’ve enjoyed a good and busy 2nd quarter. As
FF:
I’m sure you’ve seen by now, Spectra Energy reported ongoing earnings of 30 cents per
share this morning which is squarely in line with our expectations. Our earnings came
from slightly different sources than we expected, but in the aggregate, we were on plan
for the quarter. Spectra Energy’s pipeline segment delivered solid results, and our
distribution continues to perform very well. Although our Western Canada earnings were
less than they were last year, this quarter included scheduled turnarounds at 2 key gas
processing facilities, and the resulting volume loss and cost increases dampened their
earnings. And finally while commodity prices did benefit Field Services this quarter, that
benefit was muted by severe weather in Western Kansas and southeastern New Mexico,
which caused operational issues at several plant locations. The resulting margin loss and
cost increases had an adverse impact on Field Services earnings. I think you will recall,
we had negative effects of severe winter weather in the 1st quarter of the year. We
certainly didn’t expect this trend to recur in the 2nd quarter, but it did. I think the good
news is that the affected plants at both Western Canada and Field Services—they were
back on line by the end of the 2nd quarter. And commodity prices are looking robust for

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August 6, 2007

the remainder of 2007. Greg will provide more detail on the segments here in just a
moment.

Looking strategically at the quarter, we achieved major milestones toward implementing
our business plans. We’ve made excellent progress on the capital expansion program that
we’ve been talking to you about since our spin-off. We continue to estimate at least $3
billion in expansion over the ’07-’09 timeframe. Year to date Spectra Energy
Transmission’s capital spend has increased more than 80% over the prior year. As
expected, we are set to invest $1 billion in expansion projects this year, and by year end
we expect to place in service approximately $650 million of these expansion projects
which will fuel revenue and earnings growth as we move into 2008. We successfully
launched our pipeline and storage master limited partnership, Spectra Energy Partners,
which trades on the New York Stock Exchange under the ticker symbol SEP. In early
July SEP closed its initial public offering of 11.5 million units. That’s 17% of its
outstanding equity at $22.00 per unit, and it’s had a great showing since then. Consistent
with our ’07 financing plan, we realize $345 million in cash proceeds. Equally
important, I think, is the fact that Spectra Energy now has another vehicle that we can use
to realize value for our shareholders. Looking at the last half of the year with operations
now back on line after either planned turnarounds or weather outages and the strong
tailwinds blowing in our favor on the commodity and the business front, we are
optimistic that we’ll achieve our 2007 financial goals. With a little more than 6 months
under our belt as a separate, publicly traded company, I couldn’t be more pleased with
the progress that we’ve made to date toward meeting our long-term financial objectives.
With that let me turn it over to Greg Ebel to talk in more detail about the results from
each of our segments.

GE: Thanks, Fred, and good morning everyone. Earlier this morning Spectra Energy reported
2nd quarter 2007 earnings of $196 million or 31 cents per share compared with earnings
of $320 million in the 2nd quarter of 2006. After removing the effect of special items and
discontinued operations, ongoing earnings for the quarter were $192 million compared
with $264 million in the 2nd quarter 2006. A $30 million tax benefit in the 2nd quarter of
2006, which was not repeated in the 2nd quarter of 2007, was a significant contributor to
the earnings variance. A decline in the earnings from Field Services and Western Canada
Transmission and Processing largely accounted for the remaining quarter over quarter
variance. Fred has discussed with you the most significant operational drivers for the
earnings variance from last year, so I won’t repeat them here. However, I would like to
discuss the results for each business segment in a little more detail. Let’s start with U.S.
Transmission, which reported solid 2nd quarter EBIT results of $223 million compared
with $230 million in 2nd quarter 2006. This modest decrease is primarily a result of lower
gas processing volumes associated with pipeline operations in 2nd quarter 2007 compared
with 2nd quarter 2006. In addition, increased revenues from Maritimes and Northeast

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August 6, 2007

Pipeline and other expansion projects were substantially offset by higher operating costs.
Our U.S. Transmission business made significant progress during the quarter in executing
on our growth CapEx plan. Fred will discuss with you the status of several of these
projects at the end of the call.

Now let me turn to our distribution business. Distribution reported strong 2nd quarter
2007 EBIT of $54 million compared with $39 million in the 2nd quarter of 2006 or 38%
increase. These favorable results are primarily attributable to increased customer usage,
higher distribution rates, higher storage revenue and increased transmission volumes.
Storage revenues increased as a result of strong demand on storage and resulting higher
prices. Transmission revenues benefited from the completion of the Dawn Trafalgar
Phase 1 Expansion Project, which was placed into service late in 2006. The 2nd phase of
that expansion is expected to be completed in November of this year. As you can see,
our distribution segment had another excellent quarter.

Now let’s move on to Western Canada. Western Canada Transmission and Processing
reported 2nd quarter 2007 EBIT of $48 million compared with $89 million in the 2nd
quarter of 2006. The decrease in earnings was driven primarily by major planned
maintenance turnarounds at both the Pine River and Empress plants. There were no such
turnarounds in the 2nd quarter of 2006. Western Canada’s processing plants are generally
scheduled for turnaround work every 2 or 3 years, with the work being staggered to
prevent significant outages at any given time or in any single geographic area. In
addition, the Fort Nelson region realized lower revenues due to lower volumes associated
with reduced producer activity. Although 2nd quarter earnings are considerably lower
than they were in 2nd quarter of 2006, we expect performance in the 2nd half of the year to
improve significantly. Both the Pine River and Empress plants are back in service now,
and we don’t expect any major turnarounds for the remainder of the year. In addition, the
strong forward frac spread bodes well for our Empress facility.

Now let me speak to Field Services. Our Field Services business segment, which
represents Spectra Energy’s 50% interest in DCP Midstream reported 2nd quarter 2007
ongoing EBIT of $126 million compared with $148 million in the 2nd quarter of 2006.
Earnings were down for the quarter due to reduced processing margins brought on by
unplanned outages primarily in southeastern New Mexico and Western Kansas, due to a
series of severe thunderstorms and related power failures. In addition, Field Services
experienced higher operating costs in the 2nd quarter as a result of industry price
pressures, unplanned repairs and maintenance for planned outages, and higher planned
spending on asset integrity. These negatives were partially offset by higher natural gas
liquids prices and slightly higher processing volumes year over year. We expect to see a
marked improvement in Field Services results for the 2nd half of ’07. This improvement
will be driven by an expected decline in direct operating and G&A expenses in the 2nd

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August 6, 2007

half of the year compared to the 1st half of the year. Our share of that improvement
would be about $20 million. In addition commodity prices look to be in our favor in the
last half of 2007. The current crude oil strip is in the mid $70 range, significantly above
the 68.50 we assumed in our forecast. During the quarter Spectra Energy received
dividends and tax distributions of $111 million from DCP Midstream. And in early July
we received another dividend of $122 million related to a sale of assets to DCP
Midstream partners.

Now let me turn to Other, which primarily is comprised of our corporate governance
costs and captive insurance. For the 2nd quarter 2007 Other reported net costs of $26
million, which includes $7 million of separation costs. This compares with ongoing costs
of $24 million for the 2nd quarter of 2006.

Turning to our ongoing EBITDA for the 2nd quarter 2007, ongoing EBITDA was $625
million compared with $677 million in the 2nd quarter 2006. In order to make our
EBITDA calculations all encompassing, we have adjusted for interest, taxes and
depreciation for our unconsolidated businesses, Gulfstream and DCP Midstream.

Before I turn the call back to Fred, I’d like to discuss several other items. Spectra
Energy’s interest expense for the 2nd quarter of ’07 totaled $156 million compared with
$148 million in the 2nd quarter of 2006. As you may recall, 2nd quarter 2006 included
some capitalized interest for projects and businesses that had been transferred to Duke
Energy. Our effective tax rate for the 2nd quarter was 32% compared with only 22% last
year. This quarter’s effective tax rate is more representative of a normal tax rate for
Spectra Energy. The unusually low rate reflected in last year’s quarter resulted from state
income tax adjustments of $30 million related to the Duke Energy/Cinergy merger. As of
June 30, 2007 our debt to total cap ratio stood at 58%, and net debt to total cap is
approximately 56.5%; very much in line with the 55 to 60% range we told you we
expected to maintain. Finally, in May we closed on a new U.S. Credit facility of $1.5
billion, so at June 30th we had total capacity under our credit facilities of over $2.1
billion, against which we had commercial paper and letters of credit outstanding of $731
million. As you can see, this leaves us with ample credit capacity to finance our capital
expenditure program, and as we discussed with you in the past, our highest strategic
priority is effectively executing on our $3 billion growth CapEx strategy over the 2007 to
2009 period. Overall, I feel very good about where we stand financially at Spectra
Energy. Now let me turn things back over to Fred who will update you on several of the
more significant projects in our capex plan.

FF: Thanks Greg. Let me finish by providing a quick update on a few of our key growth
projects. You see this slide every time we speak with you, and that’s because our ability
to execute on our growth CapEx plans is key to our ability to deliver our stated growth

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August 6, 2007

EPS rate of 5-7%. We are very pleased with our progress on the development and the
execution of our growth CapEx projects. Year to date capital expenditures stand at $518
million; $340 million of which is expansion. We fully expect to spend over a billion in
growth capital this year, and as I mentioned earlier, we will place into service some $650
million in capital projects by year end. The projects we’re delivering on are solid value
enhancing additions; things like Northeast Gateway, the Cape Cod Expansion, Phase 1 of
the Time II Expansion, the Dawn Trafalgar Phase 2 Expansion, Pine River as well as
Egan Storage. These projects will start providing EBIT and cash flow by the end of this
year.

Let me give you a brief update on several of our more significant projects. First, let’s
talk about Northeast Gateway. That’s a project that will be in service by year end. It’s a
16-mile 24-inch offshore pipeline in Massachusetts Bay that will connect Excelerate
Energy’s deep-water LNG port to our Algonquin hub Line system. We’ve entered into a
25-year firm contract with Excelerate Energy for all of the 800 billion cubic feet a day of
capacity for this pipeline. Construction began in May, and we’re now completing the
pipe-laying process. We estimate total project expenditures of about $240 million. We
feel very good about meeting our December of ’07 in-service date.

While we’re talking about LNG related projects, let’s take a look at where we are on our
Maritimes Phase 4 Expansion. This is an expansion of the capacity on the U.S. leg of our
Maritimes Northeast Pipeline to move gas from the Canaport LNG terminal in New
Brunswick. This terminal is currently under construction. It’s being developed jointly by
Repsol and Irving Oil. It’s expected to be on stream by November of 2008 with a send-
out capacity of a BCF per day. We are doubling the capacity of the U.S. piece of
Maritimes & Northeast to over 830 million cubic feet per day to accommodate this new
LNG. This is mainly a compression project involving the re-piping of a couple of
existing compressor stations and building 5 new stations. We’re making great progress
here too. Repsol has signed a firm 25-year contract for 730 million cubic feet per day on
the U.S. portion of the Maritimes system for delivery into the northeast market. Eighty
percent of the project materials and equipment have been procured or committed. We
expect to spend about $320 million on this project and we anticipate completing
construction to meet the commencement of service from the Canaport terminal in
November of 2008.

We’re currently in construction of our Texas Eastern Time II project that involves new
pipeline looping and compression. This project will deliver 150 million cubic feet per
day of new transportation service from Lebanon, Ohio to New Jersey. We have 10- and
15-year contracts with Public Service Electric and Gas, Power as well as New Jersey
Natural Gas underpinning this expansion. This project will come into service in 2 phases.

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August 6, 2007

Phase 1 in November of this year and Phase 2 in November of ’08. We expect total
project capital expenditures here of about $210 million.

And lastly, let’s look at where we are on our Southeast Supply Header Project or SESH.
SESH involves the construction of about 270 miles of new pipeline from the Perryville
hub in northern Louisiana to our Gulfstream Natural Gas System near Mobile, Alabama.
It will interconnect with numerous interstate pipelines along the way. This project will
link the onshore natural gas supply basins of East Texas and north Louisiana to the
southeast markets giving customers there an important alternative to offshore supply.
Ninety-five percent of the capacity has been subscribed under long-term agreements.
The pipe is currently being delivered, and all of the prime contractors have been retained.
We expect to receive FERC approval a little later this year. Our construction costs for
this project will be about $400 million dollars, and we expect an in-service date in the
summer of 2008. These 4 projects alone will account for about 1 billion of the 3 billion
in CapEx that we expect to spend over the next 3 years. So hopefully, I think, this should
give you a clear sense that we are moving forward in the pursuit and the realization of
value-adding opportunities.

Let me wrap up by saying that our 2nd quarter performance was on plan. We are
optimistic that we can deliver financial results consistent with our employee incentive
target. Spectra Energy continues to prove itself as a premier provider of natural gas
transmission and storage services. We have industry dynamics that are very favorable for
infrastructure growth. We’re positioned in 4 of the fastest growing gas demand markets,
and we have access to a diverse supply base. We have a strong, I think, enviable balance
sheet, stable cash flows and the financial flexibility to handle virtually any opportunity
that arises in the sector. We continue to expect 5-7% EPS growth with a 3 to 3-1/2
percent dividend yield for a total expected return in the 8-10% range with little downside
risk. With that let’s open the lines for your questions.

O: Your first question comes from the line of Mike Heim

MH: Thanks. Couple questions if I could. Greg, last call on earnings you talked about a tax
rate of maybe 32, 33 to use for the year, and while we’re getting closer after a much
lower rate in the 1st quarter, we’re still kind of under that. Is that still a number you're
comfortable with?

GE: Yes, Mike. That is the number that we would see going forward for the year. Thirty-two
percent is a good number for this year, and 32, 33% range going forward. As you know,
future is always difficult to predict exactly on taxes, but 32 is the right number for now.

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August 6, 2007

MH: And kind of a similar question on the corporate tax. I guess I was using a number of 100
million. We’ve had 2 quarters that’s been coming in below that. Any thoughts that
maybe the 100 million is too high a cost number to use for corporate?

GE: You know, we had—what we’re trying to do—you're right. The cost have come in a
little bit lower year to date. We’ve got some pick up in the last half, but I think in that
kind of 90—$100 million range is probably the number you should be looking for, for the
full year. As you know, we’re trying to take those costs down then for next year.

MH: Can you talk about Union Gas and what weather was, and I can’t remember; do you have a
weather normalization provision there or is weather a contributor to earnings?

Well, weather is a contributor to earnings, but usually in the 1st and 4th quarter much
GE:
more than it is, obviously, in the 2nd and 3rd quarter. We don’t have a normalization of
rates. Rates are based on normalized weather, but there’s no change for improved
weather or lower weather as the pick up or hit is to the shareholder.

MH? Was weather pretty close to normal this quarter?

GE: Yeah, it was a little bit colder, but really not a significant change. The real driver up
there was having higher distribution rates as a result of our rate case from last year, and
obviously, getting some more usage from our core markets as well as the Dawn Trafalgar
project coming in as well as storage revenues.

MH: Can you tell me, what are the items that fall into the discontinued?

GE: This quarter it was a settlement with Sonatrach, which was $11 million positive. Last
2006 Q2 kind of items there, and of course that would have the Duke, so it’s not a
comparable number. When you look at our year to year, really the issues there—you’ve
got everything from Crescent Real Estate, DENA and DEI issues last year, and of course
all those businesses stayed with Duke Energy.

FF: Yeah, Mike, it’s primarily driven by the businesses that were carried under Duke Capital
last year that Duke Energy retained after the spin.

MH: Okay. And then finally as we talk about 3 billion in projects, it seems to me when we did
the road shows for the spin-off and a couple of industry presentations after, the numbers
were a little bit closer to 4 billion in greenfield and organic and storage projects. Are
there specific projects that have kind of been push back beyond 2009 now?

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August 6, 2007

GE: No, it’s good. Probably got 3 billion of the projects that we feel comfortable are under
execution and moving forward or a long ways down that development trail. Those pages
that you're talking about, that was other projects opportunities that we see could be
coming in over the future years, but 3 billion is the number we’re comfortable in terms of
expansion projects at this point in time.

MH: Okay, very good. Thank you.

O: Your next question comes from the line of Faisel Khan.

FK: Hi, it’s Faisel with Citi … If you could give me a little more color on the Field Services
side—if I was to go up to above equity earnings to the operating income line for the
entire operation, what would the numbers look like? Is there anything below the line that
could be impacting those numbers quarter over quarter?

GE: When you say below the line, you mean at Field Services?

FK: At Field Services.

GE: Well, there’s a variety of factors that are in there. The big one in terms of impact from
Field Services perspective were some O&M cost increases that we saw. Some of that
related to weather. And you did have some benefit, obviously, from commodity prices,
$9 or $10 million, but really it’s the weather impact that hurt us by about $15 million, so
you would see some of that in the revenue line and some of that in the O&M line, Faisel.

FF: The other thing, Faisel, is least year we had a pretty good gas marketing income as a
result of some basis blow outs that happened which haven’t repeated this year.

FK: Okay. I gotcha. If I were looking at kind of the impacts to that business over the last
quarter … to the reduced processing margins versus the higher operating costs, it’s
mostly the higher operating costs?

GE: I think it’s a combination of … both actually—some of the higher O&M but also the
weather too. A lot of this both in Western Canada and DCP, I think it’s important to
note, were planned. The weather hits, obviously, weren’t planned, but higher asset
integrity work, plant turnarounds, etc. That is planned, so from our perspective there
wasn’t a big surprise. The surprise is really the weather issue at Field Services for the 2nd
quarter in a row.

FK: Okay, gotcha. And on the U.S. Transmission side the … also higher operating costs
there. And I think I—I think you said you mentioned in a little bit granularity in prepared

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August 6, 2007

remarks, but I missed a little bit of that. What exactly were the higher operating costs the
result of?

GE: Well, you’ve got some pressure on wages, but more importantly we planned to spend
some more money on asset integrity. That was part of our budget this year. As you
know, those pipelines are critical to us, so making sure they're in good order is a big part
of the way we plan for the business. So there was some planned asset integrity increases
this year. And then you have some pressure just on wages and items like that.

FF: Outside services in particular.

FK: And if I remember right, the integrity costs are generally expensed at the quarter you do
that. They're not capitalized for the—into rate base. Is that correct?

FF: That’s correct.

GE: That is correct.

FK: Okay. I gotcha. Okay, great. Thanks, guys for your time.

Your next question comes from Carl Kirst.

CK: Good morning everybody.

Hi Carl.

CK: If I could just get a little more color around—even though there were plans—just so I
understand the magnitude—can you guys help me out with—of the delta in Western
Canada, how much came from the planned outage versus, say for instance, lower
producer activities, if that’s possible to quantify.

GE: Sure. If you looked at the planned outages in terms of processing revenues, that’s really
at Empress. It was about $12 million or so in revenue hit there, and then the O&M side
hit both our Pine River plant and Empress; again, both plants to the tune of about $15
million, and there's no revenue hit at Pine River, because they're largely firm contracts.
And then Fort Nelson—$5-6 million range in terms of lower producer activity,
Carl.

CK: Okay. So the vast majority was the planned outage?

GE: Yes, sir.

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August 6, 2007

CK: Great. And with respect to the Field Services—and again, the thunderstorms and the
power issue. How long was that plant outage? And is it possible to quantify what that
impact was? And if it was material, would that qualify for business interruption
insurance or can you help us out there?

FF: Carl, we don’t—our deductibles are high enough on our business interruption insurance
that it didn’t hit that level. The big one that hurt us badly was the one in Western Kansas.
That plant—National Helium is one of their very, very large plants, and it was down for 2
weeks, and it was a combination of things. We had lightning strikes that happened on us.
It also hit on the Panhandle Eastern Pipeline System and knocked their compression out,
so we didn’t have feedstock for the plant. We ended up having some equipment damage
as a result of it, and we were down for 2 weeks there, and that’s the biggest impact that
we had. At this stage it’s still too kind of—it’s a little bit early to know—give you an
order of magnitude, we’re probably talking that weather impact on revenue was probably
in the $10-12 million range. Our costs were up in the $20 million range, and it’s still too
early to figure out how much of that was actually due to some of these problems and how
much of it was other stuff, but we’re ferreting that out.

CK: Okay, now that’s very helpful. Fred, just lastly on the transmission side, I’m not sure if
this is material enough to have registered, but with Moss Bluff/Egan, we’ve seen other
people being hurt a little bit by some of the contraction in the summer-winter spread. Did
that really register on the needle at all for you guys?

No.

CK: All right. Thank you.

Thanks Carl.

O: Your next question is from Paul Fremont.

PF: Thank you. When you talk about a better result at Field Services and Western Canada, is
that relative to the 1st and 2nd quarters? Or is that relative to the 2nd half of 2006?

We’re talking relative to the 1st and 2nd quarters.
GE:

Any comment relative to the 2nd half of 2006? And have you provided comparable
PF:
quarter numbers yet for the last 2 quarters?

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August 6, 2007

GE: For the first question, I wouldn’t comment so much versus ’06 so that then again, we
had—if you take Field Services and Western Canada—again, we had expected the plant
turnarounds, so, obviously, as part of our planning process; so, obviously, those weren’t
to occur in the 2nd half, so you’ll see an improvement there. With respect to the quarter
over quarter information you were looking for, we did file last week Friday, I believe—
late Thursday or Friday—a recast of the ’06 numbers, Paul, so that should be helpful for
folks to be able to look at to be able to compare the business units.

Thank you. Lastly, any comment on the liquids to oil relationship in the 2nd quarter
PF:
relative to where it had been last year?

GE: Yeah, that was obviously better than it was last year.

FF: Paul, this is Fred. I can’t remember on a quarterly basis what the relationship was last
year. I think for the year I think it averaged 57%. Is that right John? In that range? And
we were approaching mid 60s this quarter.

PF. Great. Thank you.

O: Your next question comes from Lewis Ropp.

LR: Good morning.

Good morning.

LR: Couple of questions—and the first, I hate to ask another question about Field Services,
but should we assume that the O&M and weather impacts hit you and your partner
equally, because looking at their results for the quarter, they only showed their earnings
from DCP down about 5%, and with yours down 15, 16%, it just begs the question,
what’s the difference?

FF: They have other things that go into that besides Field Services. That’s not the only thing
in that sector. They have other business that goes in that.

GE: Fred’s exactly right, but they would have had the exact same impact out of DCP that we
would have. So whatever else they have in their segment there would make up the
difference.

LR: The other question about the Western Canada, are you seeing any change in the producer
activity in the Fort Nelson area this quarter?

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August 6, 2007

MW: No, we’re not. This is Martha Wyrsch. We continue to see a decline in drilling. That
has pretty much leveled off to where it is today, but we don’t see that pick up coming in
these winter months.

LR: Okay. Thanks, Martha. Lastly, what are you showing as the forward frac spreads there
at Empress for the 2nd half of the year?

GE: They’re in the $5.50, $6.00 range. Again, we don’t do anything different than what you
would do in terms of looking at the forward curve that you have up there at NYMEX
largely.

LR: Well, and that’s why I’m asking the question, because in your comments you said that
you saw some improvement based on the forward frac spreads, but to me they look very
similar to what they were in the 2nd quarter.

GE: Yeah, actually I think in our comments we said the forward frac bodes well for the last
half of the year versus what we had expected for the year. Remember, we, in our forecast
had thought that—and at that time it was the forward but also the average for the last
several years—more of a $3 frac spread; and, obviously, we’re seeing a higher frac
spread than that today; and then B, obviously we won’t have the plant down for what
amounted to approximately 3 weeks in Q2, in the last 2 quarters of the year.

LR: Very good, thanks.

Thanks, Lewis.

O: Your next question comes from Matthew Akman.

MA: Thanks. On Maritimes & Northeast on the expansion there, there’s a little bit of
controversy—hopefully, won’t last long—about the routing of the Canadian portion of
the expansion, so what are the, I guess, exposures or potential implications if there's a
delay in that at all if we miss the construction window this year? Are there any
implications for the U.S. part of it that you guys are building? Or is Repsol contracted
for it whenever it comes—you finish building it? How does that work?

MW: Matthew, this Martha. As far as we see, we do not expect delays that will hamper our
ability to get the Maritimes project in service. And the Brunswick Pipeline piece of it—
although there has been some noise, we have received all of the primary permits required
to build that pipeline. We’re confident that it’s on track. The way the agreements
work—we have obligations to get it online, but we have time built into the agreements to
ensure that if we had any delays, we would still meet our in service date.

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August 6, 2007

MA: So if you—just to be clear—if you meet the in-service date on the U.S. portion, you start
getting paid on that whether there's a slight hiccup on the Canadian side or not? Or
would you just delay the in-service on the U.S. side of it?

MW: Both pieces of the pipeline are required for the LNG to be able to make it to market
Matthew. I’d have to go back and look at how the agreements work between the 2. I
don’t have that squarely in my mind, but we can get back to you on that specific question.

MA: Okay, thanks. I have a question—a follow-up on Western Canada as well. How would
you guys see the year shaping up in Western Canada? Frac spreads do look good, so if
you can run … looks like the back half will be very good. On the other hand we do have
obviously this sort of—this soft point in drilling that’s continuing, so do you see on
balance then Western Canada kind of meeting your expectations this year? Or how do
you see it relative to your expectations?

FF: Yeah, I think we see it meeting expectation or being very close, if it doesn’t. The real
area that we’re having the problem is in the Fort Nelson area, but we’ve actually got
some bright spots other places, and it’s just a question of, if we continue to see the kind
of activity we see at these other plants, and we continue to see a good frac spread, we’re
pretty optimistic.

MA: Okay.

GE: Turnaround work at Pine River has been very important Matt actually. So that’s going to
be extremely helpful for us.

MA: Okay, great. One more question on a bigger picture note, the success of the MLP; and, I
guess, excluding today which is a very turbulent day in pipeline markets. The thing has
done very well along with other MLPs, and obviously probably exceeded expectation for
valuation. Would that potentially change the way you look at how much you want to use
MLPs and maybe some of the other assets? Or is your thinking on that still what it was
or is it getting maybe a little bit more aggressive and using the MLP?

FF: I think it’s a little too early. This thing is less than a month old Matthew, and you're
seeing an awful lot of movement in markets right now that I think we just need to watch,
but we will continue to evaluate that as we go forward.

MA: Okay, thanks. Those are my questions.

O: Your next question comes from Ross Payne

Spectra Energy
August 6, 2007

RP: Thank you. My question really revolves around the transmission segment. You
commented on lower gas processing volumes. Can you delve a little bit more into that
given the increase we see in throughput within the segment?

FF: Yeah, Ross. Last year we had a continuation of something that happened earlier. When
the hurricanes hit a couple of years ago, it hit gas processing very tough on the Louisiana
coast. Just based on the location of our particular assets, we happened to be a winner
there, because we had a plant that didn’t—that we could divert gas to and keep
processing, so we processed a lot of additional gas from other plants. By this year
everything now is back on stream, and those streams have gone back to their original
processors where they were contracted, so that’s the primary reason for the volume
decrease.

RP: Okay.

FF: We just had an extra good year last year because of that hurricane impact.

RP: Gotcha. Okay. With the increased throughput across the rest of your systems, are you
seeing any kind of pressure on margins relative to last year, and is that driven at all by the
introduction of Rockies Express or anything else?

FF: No. To this point we’ve not seen any pressure at all on margins.

RP: Okay.

FF: You’re talking transportation margins?

RP: Right.

FF: Yes.

RP: Right. One final question on Texas Eastern and East Tennessee, what’s the average life
on your contracts here?

FF: Martha, do you know that off the top of your head?

MW: I do on Texas Eastern; it’s about 8-1/2 years average life, and then on East Tennessee—I
don’t have that in my head. Patti do you? Okay, 9.3 years.

RP: Great. Okay. Thank of very much.

Spectra Energy
August 6, 2007

Thanks Ross.

O: Your next question comes from Lasan Johong

LJ: Hey Greg. Hi Fred. Quick question—on a comment Fred you made during the call; did
you say that you're targeting 3 to 3-1/2% dividend yield? Was that what-I heard
correctly?

FF: Yes.

LJ: Okay, that’s just the starting point, right? And you're expecting the dividend yield to go
down after that?

GE: Well, obviously the stock price goes up, the dividend yield’s going to go down. But I
think maybe the way to look at it—the other way to look at it is also on the payout side,
and we’ve said we targeted approximately a 60% payout, so obviously to do that as
earnings grow, there’s an opportunity to grow that dividend to put it in line with that 60%
payout.

LJ: Okay, that makes sense to me. On the distribution side, I had a question about the
operating performance there. Very strong—and I’m guessing that was weather related?

GE: Not really. A variety of things; there’s some weather. We increased usage in our core
market is partially driven by weather, but just some of the economic growth in Ontario;
but equally important, obviously, settlement of a rate case last year increased rates, but
also the storage and transmission. Remember, Dawn Trafalgar, which is a 3-year phased-
in project. The first phase came in in late ’06, so we get he full benefit of that this year.
The next phase coming in in late ’07 for the benefit next year and then storage—very,
very positive markets there. We’ve seen storage in kind of the much higher rates than
what we’ve seen historically more in the $2.00 range for long-term deals.

LJ: Lastly, any concerns from the current credit situation?

GE: No, in fact I feel very good. I’m very pleased that we’ve got the CP program … up and
running and the new credit facility is in place. We don’t have a lot of capital markets
work for the remainder of the year from a credit perspective. And obviously most of the
customers we serve on the pipeline side 75, 80% would be strong investment grade
credit, so all that I think bode well from our perspective.

LJ: Excellent. Thank you much.

Spectra Energy
August 6, 2007

GE: Thank you.

O: Your next question comes from Nathan Judge.

NJ: Good afternoon.

Hi Nathan.

NJ: I just wanted to follow up on a couple of quick questions on exchange rate impact in the
quarter. I apologize if you’ve answered this. And then also, if you can just go back to
what kind of—if I were to look at Fort Nelson impact on revenues, is that really going to
be started to be extrapolated out to the future? Or is there something special going on
with that?

GE: Exchange rate was pretty minimal. Remember, we’re largely hedged to the changes in
exchange rate because of having a lot of Canadian dollar debt; about a million dollars for
the quarter positive, Nathan. And for the first 6 months, obviously, we were ahead of the
game in 2nd quarter with the strong Canadian dollar, but that was not the case in the 1st
quarter, so net-net we’re about online with where we thought currency would be for the
year. The 2nd question with respect to Fort Nelson, again, the revenue impact there was
about $5-7 million. And as Martha said, it’s not that we see that getting worse, but the
question is just how does that come back. Western Canada is one of the most expensive
places to operate in North America, if not the most expensive from a drilling perspective,
so it’ll be a classic market dynamic supply and demand issue that’ll bring back the
drilling.

NJ: Thank you very much.

Thanks Nathan.

O: You have a follow-up question from the line of Carl Kirst.

CK: Really quickly. On the midstream on Field Services, has there been any change in the
mix of keepwhole, percent of proceeds and really ultimately has there been any change in
your NGL sensitivity?

FF: No, it’s pretty much right on target.

Spectra Energy
August 6, 2007

CK: Okay, great. Lastly, have you guys put out what an EBIT is associated with the other 650
million capital projects that come online? We’re sort of looking at around 80, 85 million.
I didn’t know if that was in the right zip code or—

GE: No, we haven’t Carl. First, we’ve said if you take the $3 billion thinking the 10-12%
return on capital employed (so EBIT over capital employed there) and should get you a
full year view of the kind of returns we’d expect.

CK: Great, Greg. And that capital employed—is that a pre-tax or after-tax?

GE: That is pre-tax, so that would be EBIT over capital employed.

CK: Thank you.

GE: Thank you.

JA: Thanks for joining us today on the call. As always if you have any additional questions
later in the day, feel free to give Patti Fitzpatrick or me a call. For those of you who may
not have seen it, we did release 2 8-Ks yesterday—I’m sorry, on Friday, and the first was
to recast the financials in our 2006 10-K to conform to our current reporting segment, and
the second one was to report our 2006 earnings by quarter. So those 10-Ks can be
accessed at our website. That’s information that many of you have been requesting, so
we’re happy we’re able to provide that at this point. I also want to remind you that we’ll
host an analyst breakfast in New York on Tuesday, August 14 and a lunch in Boston on
that same day, so if you haven’t signed up yet, please do. We’d love to see you there.
The breakfast meeting will be webcast and you can find details of that webcast on our
website. Thanks again for joining us today.

[Tape ends]

spectra energy 2Q2007Transcript

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