Transcript Techincal Conference

122

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ x

IN THE MATTER OF: :

ORDER NO. 720, PIPELINE POSTING : Docket Number

REQUIREMENTS UNDER SECTION 23 OF THE: RM08‑2‑000

NATURAL GAS ACT :

‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ ‑ x

Hearing Room 2C

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, D. C. 20426

Wednesday, March 18, 2009

The above‑entitled matter came on for technical

conference, pursuant to notice, at 9:00 a.m.

BEFORE:

Anna Cochrane, Presiding.

APPEARANCES:

Federal Energy Regulatory Commission:

William Murrell

Jerome Pederson

Christopher Ellsworth

Christopher Peterson

Arnie Quinn

Steven Reich

Gabriel Sterling, III

Panels:

Roger A. Farrell

President & COO

Southern Union Gas Services, Ltd. (on behalf of TPA)

Larry Black

Manager, Gas Purchases and Transportation

Southwest Gas Corporation

Vonda Seckler

Managing Executive, Gas Supply

Ameren Corporation (on behalf of AGA)

Robert W. Young

Director of Scheduling

Energy Transfer (on behalf of TPA)

APPEARANCES (Continued):

John Ellis

Senior Counsel

San Diego Gas & Electric/Southern California

Gas Company

Bridget Shahan

Assistant General Counsel & Chief Compliance Officer

Nicor Gas

Michael Novak

Assistant General Manager, Federal Regulatory

Affairs

National Fuel Gas Distribution Corporation (on

behalf of AGA)

John Ellis

Attorney

San Diego Gas & Electric/Southern California

Gas Company

Will McCandless

Director Pipeline Portfolio ‑ Commercial Operations

Exogex LLC (on behalf of TPA)

P R O C E E D I N G S

(9:00 a.m.)

MS. COCHRANE: Good morning. I'm Anna Cochrane.

Acting Director of the Office of Enforcement.

On November 20, 2008, the Commission issued a

Final Rule in Order Number 720, Pipeline Posting

Requirements, under Section 23 of the Natural Gas Act, which

amended Part 284 of the Regulations to require, among other

things, major non‑interstate natural gas pipelines to post,

on a daily basis, certain information regarding scheduled

volumes of natural gas to be transported.

Requests for rehearing of the Rule, were filed on

December 22nd. On January 15th of this year, the Commission

granted and extension of time for major non‑interstate

pipelines to comply with the requirements of the Rule, until

150 days following the issuance of an Order on Rehearing.

On February 24th and March 11th, the Commission

issued Notices announcing this Technical Conference, to be

held regarding certain issues raised on rehearing of Order

Number 720.

The Notices identified three topics for

discussion: One, the definition of "major non‑interstate

pipelines;" two, what constitutes scheduling for a receipt

or delivery point; and, three, how the 15,000 MMBtu per day

designed capacity threshold should be applied.

The March 11th Notice provided an agenda with

specific questions on these topics, and announced the panels

to be held today, including a panel on compliance costs.

The purpose of this conference is for Commission

Staff to gather more information and explanation to better

understand technical issues that were raised in certain

rehearing requests.

We're not here to discuss the merits of Order

Number 720, or issues beyond those listed in the Notices.

We understand that certain parties have argued in comments

and on rehearing, that the Commission lacks the

jurisdictional authority to promulgate the Rules in Order

No. 720, and others, that there was a lack of notice for the

decisions made.

Those arguments and others, will be addressed in

the Commission's Order on Rehearing, and we do not intend to

discuss them today.

The topics on today's agenda were chosen because

we felt that additional information would better inform the

record and assist the Staff and the Commission in addressing

these issues on rehearing.

I'll note that we have a Court Reporter with us

today, so that the transcript of this proceeding will be in

the record. I know that this a rulemaking, and so there

aren't ex parte considerations for discussing things with

Staff, but we felt that in order to have this discussion

and be able to rely on the discussions that we might have to

further address these issues, it would be good to have them

in the record, so that's a driving factor behind this

conference.

No one should interpret the selection of issues

discussed here, to be indicative of the Commission's

ultimate determination on these or other issues raised in

the rehearing request.

Before I start, I note that any of the views that

may be expressed during this conference, by me or by any of

the other Staff members participating today, are our own

individual views and do not reflect the views of the

Commission, the Chairman, or any individual Commissioner.

So, with that, with me at the table to day, are

Jerry Pederson, Dr. Arnie Quinn, Steve Reich, Chris

Peterson, Chris Ellsworth, and Gabe Sterling, all with the

Office of Enforcement.

The panelists have been asked to provide a

response to the questions that were listed in the March 11th

Notice, limiting those comments to about five minutes.

After each of the panelists has made their presentations,

Staff will then ask questions.

So the first is panel is designed to review

structural issues in the Commission's designation of major

non‑interstate pipelines, and I really appreciate you coming

today to talk about this issue.

We have Roger Farrell, President and Chief

Operating Officer of Southern Union; Larry Black, Manager of

Gas Purchases and Transportation for Southwest Gas

Corporation; and Vonda Seckler, Managing Executive, Gas

Supply, for Ameren Corp.

And I misplaced my agenda, but I understand that

‑‑ so, Roger, you're speaking on behalf of the Texas

Pipeline Association, correct? Larry Black, Southwest Gas

Corporation, filed their own Request for Rehearing, and

Vonda Seckler is speaking on behalf of American Gas

Association.

Thank you very much. We can just start.

MR. BLACK: We have passed it back and forth,

that maybe I would go first, if that's all right.

MS. COCHRANE: Okay, if you guys have come up

with an agreement, that's fine.

MR. BLACK: I need to turn this light off.

MS. COCHRANE: Yes, you just flip it.

MR. BLACK: Thank you. Good morning, ladies and

gentlemen. Thank you.

For no other important reason, other than the

record, I would note that my title is actually Director of

Gas Supply.

Now, this is a perfectly good title from a few

years ago, but it has changed.

I'm here representing Southwest Gas Corporation,

to address the first issue on your agenda, defining "major

non‑interstate pipelines," and the first two points

thereunder on the agenda, and how they apply to the 50

million decatherm threshold for reporting that's been set

forth in the Order.

The heart of the issue, we believe, emanates from

the purpose for which the information is to be reported.

With the understanding that the requested data is

meant to further the Commission's understanding of what

activities impact the natural gas market and where an impact

takes place, we believe that Southwest represents a logical

example of why the segregated or non‑contiguous systems

should be viewed that way, independently, for purposes of

meeting that threshold.

I would note that I've been doing this for many,

many years, both in the interstate pipeline business, the

producer side, and now for many years with the LDC.

I believe that there's a terminology question

that always comes up. There may not be any regulatory or

legal distinction, but when anybody in the industry talks

about pipelines, an interstate pipeline, an intrastate

pipeline, quite frankly, they never visualize a local

distribution company in that conversation.

There are, of course, interstate and intrastate

pipelines, some of which also own distribution companies,

many of which do not, but when someone talks about the

pipelines, they typically are not talking about the

distribution company.

Southwest has six operating divisions located in

three states. I have prepared a little map, and I apologize

for its somewhat crude nature. It was not designed for this

purpose, but I tried to put it forth to just give you an

indication of where these areas are, as I talk about them.

They are not interconnected with each other in

any way; they're not separate legal entities, though they do

represent different state jurisdictional areas.

One might ask, well, why are these systems

segregated this way, or non‑contiguous? The answer to that,

is simply that they were built at different times, in many

cases, by different companies, and always to serve different

markets.

Southwest began its distribution business in the

area of Southern California, where the Company actually

started as a propane company. I will add that if you look

at this map, don't let it be misleading.

The shaded areas that you see on there,

represent Southwest franchise territories. That's not to

imply that there are, indeed, distribution lines throughout

every bit of that shaded area. Much of that is desert with

cactus and jack rabbits in it, but it is a franchise area.

Somewhat later, they built the new distribution

system in southern Nevada, primarily to serve the Las Vegas

area, and, later still, a new system in northern Nevada, to

serve the few people that lived in northern Nevada at that

time.

These created the Southern California, Southern

Nevada, Northern Nevada Divisions that we refer to. They

are all geographically separated and they are all

independent of each other.

In 1979, Southwest acquired the gas distribution

business of what was then Tucson Gas and Electric Company,

thus forming what we now would refer to as our Southern

Arizona Operating Division.

In 1984, Southwest acquired the gas distribution

business of Arizona Public Service, forming what we now

refer to as the Central Arizona Distribution Business.

Clearly, those were separate businesses owned by separate

companies, and were not connected then and are not connected

with each other now.

Part of what is now Northwest and Northern

California area, was acquired in earlier years. In 2005, we

acquired the distribution business of Avista Corporation,

around the Lake Tahoe area, thereby completing what we now

refer to as our Northern California Operations.

Some of these are separated by state borders,

some by hundreds of miles, some by the fact that they were

built by different companies at different times, and all

were built to serve different markets.

Today, they are all Divisions operated by

Southwest Gas.

Because of their construction and their

operation, and, in most cases, also their geographical

separation, the operations and the usage in any one of these

segregated systems, does not really impact the marketplace

that's associated with one of the others.

In all of these six, except one, the demands are

heavily weighted to residential, small commercial, heat‑

sensitive load like you would anticipate from a distribution

company, the one exception being Southern Nevada, where we

do have a substantial load behind our system of power plant

operations.

Four of the six areas are relatively small, and,

independently, would fall well below the 50 million

decatherm threshold, but, more importantly, really, because

of the size and the makeup of the market demands on them,

reporting data pursuant to Order 720, would not really

contribute any meaningful addition to the marketplace

intelligence that we believe you are trying to gather.

I'll close with just a few details concerning all

of our distribution areas, much of which I think will also

relate to what you'll hear in the later panels.

Aside from the usual bundled retail sales, all of

the transportation service that's done for others on our

distribution systems, is only for our end‑use customers who

are behind our system.

And it's all done pursuant to state‑regulated

tariffs and state‑approved agreements. Southwest does not

schedule gas to end users off any delivery points on its

system, nor does it schedule gas across its system.

No gas or capacity can be traded between parties

on our facilities.

In every area, actually, Southwest serves as the

operator and gatekeeper for deliveries from an upstream

pipeline. In all cases but one, that's an interstate

pipeline.

The exception to that is the Southern California

area, where our facilities are located entirely behind the

facilities of Southern California Gas Company and PG&E. We

have no interstate connections at all there.

And those points where we do receive that gas on

the interstate system, are all at known, existing interstate

scheduling points. Our facilities, our only receiving

points there, in all areas except Southern Nevada, which is

an exception I'll discuss, all the gas scheduled to

Southwest by an upstream pipeline, is scheduled to what we

would refer to as virtual delivery points.

They are receipt points for Southwest, behind

which there are anywhere from several to many meters, but

none of which are actually scheduled interconnections.

Only in Southern Nevada, do we have direct

single‑meter interconnects where gas is scheduled by the

upstream interstate pipeline company, and that information,

of course, is available as what's scheduled there and what

the available capacity is there.

It's also the information that's already being

reported by the interstate pipeline company.

With that, I believe I will conclude and say

thank you for the time to speak to you.

MS. COCHRANE: Do you have a preference for who

goes next? Vonda?

MS. SECKLER: Good morning. I represent Ameren,

who is a member of AGA, and the Ameren Corporation has four

LDCs: One in Missouri, Union Electric, and three in

Illinois, Central Illinois Light Company, Central Illinois

Public Service, and Illinois Power Company.

All four of these LDCs were formed by a series of

acquisitions to form Ameren Corporation's LDC Group, mostly,

independently operating, except for a few emergency

interconnects between the Illinois facilities, and those

interconnects are only used for emergency system operating

purposes.

Within each of these LDCs, there are many non‑

contiguous systems, small load centers, mostly residential

and small commercial heat‑sensitive load.

I've provided you with one example of a map of

the Central Illinois Public Service System, which represents

the non‑contiguous areas of our systems. Within that

Central Illinois Public Service System, there are about

seven different service areas, and on that map, you can see

that there's mostly non‑contiguous areas.

Very few of these are interconnected with each

other. Some are served by one pipeline, some are served by

more than one pipeline, but they are typically not

interconnected within each other.

If our companies are looked at individually, only

one of the Illinois LDCs would meet the 50‑million delivery

threshold. We contend that, as an LDC, that we should be

permitted to look at our non‑contiguous areas.

These are areas where there is no market being

developed, just by the nature of the customers that are

behind those gates, heat‑sensitive, and we would like for

clarification that when we look at the delivery threshold

facility‑by‑facility, that the non‑contiguous areas could be

segregated and looked at on their own merits.

MS. COCHRANE: Thank you. Mr. Farrell?

MR. FARRELL: Thank you. Just for a point of

reference, I come here with a background of ‑‑ actually, I

have an engineering degree, and I actually have designed

facilities and gathering systems; I've operated them, I've

been involved in the nomination, scheduling, and, of course,

at the management level.

So I'm coming with a background of experience. I

want to address, on behalf of the Texas Pipeline

Association, the questions that have been posed concerning

stub lines and the non‑contiguous nature of the 50 million‑

decatherm threshold.

I'm also going to recommend some solutions that

would allow us to capture the information that would further

your objectives, while minimizing the demands and burdens on

our industry. Obviously, our industry, like many

industries, is in difficult times today.

If you don't mind, can I just make some quick

sketches up on the board? I want to just ‑‑ and you may

have seen a lot of this before.

I'm going to talk a little bit about the

gathering system.

MS. COCHRANE: Could you just wait a second? Let

me check with the ‑‑ can you hear him, if he's over there?

(Pause.)

MR. FARRELL: I can speak fairly loud, so you'll

hear me. I'm just going to sketch a gathering system.

A gathering system has three functions: To

aggregate supplies ‑‑

MS. COCHRANE: I'm sorry, just logistically,

could you ‑‑ what were you suggesting, Andrew?

(Discussion off the record.)

MR. FARRELL: All right, the third time's a

charm.

MS. COCHRANE: We'll flip it around for the

audience, when you're done with your sketch.

MR. FARRELL: All right. A gathering system has

three functions: Aggregate supply, condition gas, and get

it to market, okay?

The aggregation piece starts off with the wells,

and most gathering systems connect hundreds, if not

thousands of wells, okay?

We connect them with lines, and then we install

compressor stations sometimes, take it from low pressure to

high pressure, and these wells have Btu contents anywhere

from 300 Btu per cubic foot, up to 1400, 1500 Btu per cubic

foot.

They contain liquids, they contain hydrogen

sulfide, CO2, the full gamut, not ‑‑ you know, there are

some wells that are pipeline quality, by nature, but

certainly, in the majority of the cases, the gas has to be

conditioned in order to be sold, to be sold into the

interstate or intrastate commerce, okay?

The Btu content of 1050 or less, would be

required. So, essentially, we gather all these wells, and

this is just a single system; we come down here and before

we do anything, we run it through a dehydrator.

We take out water, because when the wells produce

gas, the gas is typically saturated with water vapor, and

that water vapor, before it goes into a processing plant,

had better be taken out or it's going to freeze and clog up

my system, and certainly you can't go into the downstream

pipeline with water.

Downstream pipelines have seven pounds or less.

After you dehy, you do ‑‑ you treat. If you treat, you take

out CO2, you take out hydrogen sulfide, you can take out

nitrogen, which is a whole different process, but you take

out nitrogen.

Those are unwanted components in a gas stream.

Once again, there are certain levels that you cannot, if you

don't take them out, you'll get shut in by the downstream

pipelines.

After you do that, you process the gas. We call

processing essentially ‑‑ you know, we cool the gas down to

minus‑150 to minus‑200 degrees Fahrenheit, and what happens

there?

The liquids fall out. All the liquids, with the

exception of methane and some ethane, everything else falls

out. Most of the ethane falls out, butanes, propanes,

natural gas liquids, and all those have to be taken out

before they go to the market. Once again, the interstate

pipelines cannot take the gas, for the most part ‑‑ there

are some gathering systems with some gas that's produced,

that is pipeline‑quality, but many and a lot of it is not,

and so this a vital piece.

These liquids, natural gas liquids, come out of

the processing plant, and at least the majority of us go to

Mt. Bellvue, Texas, through pipeline networks or Oklahoma,

Kansas area, for fractionation.

Once we've gone through this whole train, we now

have gas that is fungible, we can sell it into the

marketplace. Okay, at these plants, we go into the stub

lines.

Stub lines essentially will be a high‑pressure

line, for the most part, and that will be pressure

sufficient to get into the market. The intrastates, the

interstates, possibly an end user, but, typically, the

intras and inters.

So, you come out of the plant, and these stub

lines go from a few hundred feet, to miles. And the stub

lines, all they do is, they get you to market, okay?

An individual plant may go to one market, it may

go to two markets, it may go to five markets; it depends on

where you are on the grid. For our purposes, we want to

have as many markets, for a couple of reasons:

Number one is, it's a competitive environment, so

the better markets that we have, obviously, we can offer

better deals, so to speak, on a commercial end, plus, if you

have one market, what happens if your market, the interstate

pipeline, goes down for maintenance? You're shut in;

there's nowhere to take your gas.

So, typically, you try to lay these stub lines to

local markets, okay? And the market is very, very

efficient. I mean, we ‑‑ you know, the price discovery that

you can get in the interstates and the intrastates, you

know, we're very good at trying to find where the best deal

is for our customers.

There can be more plants connected to one system,

you can have a couple of plants, and that's where you get

into the contiguous/non‑contiguous situation.

Southern Union itself, we have four plants.

We're connected to stub lines that are interconnected, they

go to multiple markets. The markets are always the intras

and the inters, okay?

We have companies in the Texas Pipeline

Association, that have gathering systems in different

states, connected to different intrastates and interstates.

You know, from our perspective, the 50 million

decatherms, if reporting is done on the 15 million a day

threshold, into the intrastates and into the interstates,

essentially all this gets captured, okay?

It gets captured and it's just a matter of how

many times we want to capture it, capture the same

information. One day, we may be going somewhere, next day,

we may be going to a different place.

But at the end of the day, whether you're

contiguous or non‑contiguous, if you have enough volume

going into the intras and inters, those volumes will be

captured under a 15‑million‑a‑day‑threshold on the delivery

side.

So that is the purpose of the stub lines.

Now, let me ‑‑ we agree ‑‑ and there was

something in the Order that talked about ‑‑ that said that

the Commission said that the supplies upstream to a

conditioning plant, are not fungible, and we agree with

that.

And, moreover, supplies upstream of a

processing/conditioning/treating plant, those are not

pricing points; it's not bought and sold upstream of the

plant.

Furthermore, upstream of a plant, about 99

percent of the meters for the wells, supply sources,

upstream of a plant, fall below the 15 million a day

threshold.

Most of the wells in this country are small ‑‑

thousands, tens of thousands, so capturing any data upstream

of a plant, really does not serve the purpose of really

capturing the essence of the volumes flowing into the

marketplace.

We're going to talk, with the subsequent

speakers, the nomination and scheduling process that we

think works well to capture the volumes that come out of the

processing, and, also, I think, address some of the concerns

of the local distribution companies.

As I said, the contiguous ‑‑ we're contiguous; a

lot of companies are not contiguous, but if you have the

right 15 million a day threshold on the inters and intras,

you will capture the LDC business, you will capture the

gathering business.

So it's a matter of how redundant do we get in

reporting volumes. In the case that I laid out here, what

would we report? Certainly reporting into the markets, is

doable. There would be a handful, you know, five to ten,

depending on how massive you system is.

The intrastate pipelines are a different matter.

They're much more flexible, they have more ability to move

gas between points, they might take gas in from other

pipelines, or back out, they're much more complex.

But at the end of the day, what they do, is move

gas very efficiently from markets here to markets there,

probably mostly driven by price or demand.

Now, the difference there, also, is that many of

the intrastates have truly markets attached to them, and

whether it's an electric generation plant, whether it's

flowing into an LDC, fertilizer plant, they probably are

going to have some sort of a market.

But once again, deliveries over 15 million a day

would be captured on the supply side and on the market side.

So what I would like to come away with ‑‑ you

know, I'm probably kind of revisiting this thing, but I

believe that a gathering exemption would be warranted, but

if you don't believe that a gathering exemption is

warranted, I want to be very clear that we see points

upstream of a gathering system, do not need to be reported,

because they won't provide meaningful information to the

Commission or to anyone else.

Then also I'd like to propose that we adopt the

posting requirements that we're going to proffer in the next

segment, that I think resolves a lot of the issues and

concerns of the LDCs, and some of the other market

participants.

And with, that, I'll conclude my remarks.

MS. COCHRANE: Thank you very much. Does Staff

have questions?

MR. REICH: Thank you very much. Mr. Farrell,

there were a number of questions or a number of items. One

of the issues raised in the Rehearing Request, was something

about gathering lines that don't go through processing

plants.

And can you explain a little, how that works,

versus the chart that you put together?

MR. FARRELL: I'll address it two ways, and I

don't know exactly what was discussed. I know when I came

in, there were some discussions, but, you know, the stub

lines, to me, serve a purpose, you know, that they are a

gathering facility that serve a market access function,

solely.

It's possible to have gathering lines that are

not treated or processed, and maybe are just dehy'd or

possibly dehy'd by the producer at the wellhead, that would

‑‑ could go into a market, directly.

That would be about the only one I would, you

know, the only gathering function that would be downstream

of a process facility that I could come up with.

MR. REICH: Is that common?

MR. FARRELL: There are a lot of gathering

systems that go directly into intrastates and interstates,

that do not ‑‑ that are not processed.

The gas is ‑‑ I mean, I don't know relative

volume, but there is gas that is pipeline quality that

doesn't need processing. But, once again, if there are

large volumes, if they are over 15 million day, into the

inter or intra, they would be captured under the Rule.

MR. REICH: Thank you, thanks. I have one

question about stub lines. In terms of the definition of

"stub lines," do they ‑‑ is it possible for stub line to

serve a customer directly, or does it ‑‑ or do they

generally just go into the inter and intra?

MR. FARRELL: By far, they go into inters and

intras. Are there cases where they go to a customer?

Probably so, but I don't ‑‑ you know, I don't have any

anecdotal numbers to say what percentage, but it wouldn't be

very large.

MR. REICH: Thank you.

MR. PETERSON: Yes, Mr. Farrell, I have a couple

of followup questions for you. Can you characterize the

typical output of the plants you've drawn up here?

I suspect it's a range, but can you give us a

flavor for the magnitude of the million cubic feet per day

ranges for these facilities?

MR. FARRELL: Of course, it's economy of scale,

but I've been associated with plants that have been five or

ten million cubic feet a day outlet. The typical plant that

we deal with today, is probably more along the lines of 100

million cubic feet a day, but there are many plants that

are much greater than that, around our producing region, and

there are plants that are probably 400 million cubic feet a

day.

And then in your discussion, I think when you

talk about taking the gas to market, what do you mean? More

specifically, what's the market you're suggesting that the

output of these plants goes to?

MR. FARRELL: The market, literally, are sales

delivered into intrastates or interstates.

MR. PETERSON: And when you say that given the

range of the output sizes of the volume leaving the tailgate

of these plants, I think what you're getting at, is that

these could show up as interconnected receipts for other

parties, whether they are interstate natural gas pipelines,

for which we would already see those volumes, presumably, or

for the major non‑interstate systems that this Rule aims to

get better coverage of; is that correct?

MR. FARRELL: That would be correct.

MR. PETERSON: And I think you just said you're

not sure how much of the gas that is pipeline quality, that

does ‑‑ it is able to skirt going through processing,

because it already has, you know, chemical or, you know,

water attributes that are sufficient that it can free‑flow

on the system.

We've talked about this internally. Do you have

any guidance you can give us for how big that is?

MR. FARRELL: In the marketplace, I don't. I

will say that I know that we have a system that can flow,

you know, 100 million cubic feet a day, and go directly to

market.

Now, that volume will be captured by an

intrastate pipeline.

MR. PETERSON: Right.

MR. FARRELL: But, I mean, going back through my

history, I would say ‑‑ and I'm, you know ‑‑ well over 50

percent is going to have to have some sort of ‑‑ I mean,

certainly dehydrated, and depending on what basin you're in,

there will be some level of treating or processing.

MR. PETERSON: I guess, lastly, in terms of

deliveries out of your system, do any of this gas go

directly to end users, or, more typically, is it nearly

always carried through either an interstate network or a

major non‑interstate system?

MR. FARRELL: Your last statement is correct.

Gatherers go to other companies who take the pipeline

quality gas to the downstream market, and those ‑‑ the

receiving pipeline off the stub line, will be major non‑

interstate. You know, there are certainly some in TPA in

Oklahoma, in Texas, and Louisiana, or the interstate.

And they will be the ones, typically, that have

the connected end users, and, certainly, the intrastates

will or may go to the interstates, as well, so, basically,

the gas can go to wherever it's needed.

But the intrastates are very ‑‑ have very

flexible systems that allow gas to go bidirectional in their

systems at times. They have a lot of compression at key

points, but they're just ‑‑ the capability, certainly of the

larger ones, are just very good at finding where the best

value is for the customer.

MR. PETERSON: Thank you.

MR. REICH: Now we'll turn to Ms. Seckler and Mr.

Black.

Ms. Seckler, you raised in your presentation, you

talked about your four operating companies. Is that the

right term that you used?

MS. SECKLER: That's correct.

MR. REICH: And that they are non‑contiguous, and

then within those companies, there are various non‑

contiguous companies.

MS. SECKLER: Correct.

MR. REICH: Am I correct?

MS. SECKLER: Yes.

MR. REICH: Is there a way that we can

differentiate ‑‑ well, how do you differentiate what makes a

non‑contiguous part of a single system, versus non‑

contiguous operating companies within your overall Ameren

umbrella?

MS. SECKLER: Well, the four LDCs are separate

legal entities, and then within one of the legal entities,

there's various non‑contiguous service territories, so it's

delineated by the legal operating entities and then within

those operating entities, that whole service territory is

operated, I guess.

MR. REICH: I mean, do they ‑‑ are they operated

by ‑‑ you know, do they have different control rooms?

MS. SECKLER: No, there is one control room for

everything. We nominate on the interstate pipelines,

individually, by LDC, and then the control rooms move that

gas, based on those nominations on interstate pipelines

through the distribution areas.

MR. REICH: So they nominate individually; they

operate together?

MS. SECKLER: Yes.

MR. REICH: And in terms of the contracting and

gas supply and all that, that is a shared function?

MS. SECKLER: Well, the contracts with

interstate pipelines are separate, by legal entity.

MR. REICH: So the transportation contracts are

separate; supply ‑‑ you ‑‑

MS. SECKLER: Supply contracts are separate, by

legal entity, also.

MR. REICH: Okay. Mr. Black, is that similar on

Southwest?

MR. BLACK: Yes, I believe that's similar. We,

while we're one legal entity, if you will, hold

transportation contracts on the upstream pipelines for each

of the different areas.

Certainly, it needs to be done so for the state

jurisdictional differences. There is a centralized

purchasing function, but the supply contracts for the gas

supplies are done separately, and the transportation

arrangements that are held by contract, are also separate

for each of those.

MR. REICH: Both of you talked about parts of

your ‑‑ if you look at individual parts of your

organizations, your companies, certain parts would still fit

under the 50 million MMBtu, versus the ones that didn't fit

under it, if you treated them separately.

Is there, in terms of operations associated with

larger customers, power plants and such, is ‑‑ for the

larger parts of your entities, do they ‑‑ is there some way

‑‑ how are those treated in those entities, versus how power

plants or large customers would be treated in the smaller

parts, entities, of your company?

MR. BLACK: I'll stake a stab at that.

(Laughter.)

MR. REICH: I'm sorry, I may have gotten lost in

the middle of that.

MR. BLACK: I think I've got the question. By

and large, the only real major on‑system transportation

loads we have, would be in our Southern Nevada area, which

has a substantial power plant ‑‑ a series of power plant

loads behind that and on that distribution system.

They're not really handled any differently, other

than as with any major customer, particularly one who has

what may be a volatile load pattern like a power plant might

be. We have much more ongoing and regular communications

with those customers about what their plans are for the

day, the gas that they intend to get delivered through our

system for their use that day and so forth, where in most of

our service territories, the demand, other than our

residential heat‑sensitive load, is a commercial/industrial

load that's fairly flat, fairly regular on a day‑to‑day

basis, and really doesn't require a lot of hour‑to‑hour, or,

you know, minute‑by‑minute communication.

So that's really the only difference. The tariff

practices and the agreements that we have with those

companies, are essentially similar, but, certainly, you have

a different relationship with a major power plant that's

behind your distribution system, just as a passing of

knowledge back and forth between their operators and our gas

control people, so you will have some ongoing idea of what

they may be doing from time ti time.

MR. REICH: That's exactly what I was asking.

MS. SECKLER: Ours is similar to Southwest Gas.

The only thing I would add, is that those power plants and

industrial loads that are behind our system, we still ‑‑ and

I think they're going to get into this in the next panel ‑‑

but we still don't schedule to their meters; they still

schedule to the interconnect with the pipeline, and then we

basically balance their load with what they've scheduled,

based on our service tariffs that are filed with the state

commissions.

They could be scheduling on an interstate

pipeline for themselves, or a marketer may pool a bunch of

those customers together and schedule, but we don't schedule

the individual meters. I know that's on the next panel, but

I'd just like to add that to Larry's comment.

MR. BLACK: And I'd repeat that that's the same

for us. All of the deliveries off of our distribution

facilities, to any of those, say, generating plants, is all

done in accordance with the state tariff provisions, and we

don't do meter delivery scheduling to any of our end users.

MR. REICH: Thank you.

MS. COCHRANE: Chris?

MR. ELLSWORTH: Mr. Farrell, going back to the

processing plants and stub lines and things like that, I

think I read in the TPA comments, that there are instances

where there will be pipelines that actually bypass the

processing plant.

Assuming that is not pipeline‑ready gas, where

does that gas typical go to? Is it being sold to a

petrochemical plant or something like that, and what kind of

transactions go on in that process?

MR. FARRELL: Well, certainly if it gets into a

major non‑interstate pipeline, it's going to be pipeline

quality.

MR. ELLSWORTH: Okay.

MR. FARRELL: There may be instances where a

gathering line ties to a market, but that will be a very ‑‑

I can't say "rare," but it will certainly be an exception.

MR. ELLSWORTH: Okay.

MR. PEDERSON: Ms. Seckler, if I can go back to

the noncontiguous systems. I thought I heard you say that

the Illinois system operates independently but for certain

emergency situations. Did I hear that right?

MS. SECKLER: That's correct.

MR. PEDERSON: What are those situations?

MS. SECKLER: Well if there are pressure issues,

or if we have a major outage of like a company‑owned storage

field; or it could be day to day, maybe weather changes. We

have basically one interconnect between each utility

distribution system for those type of situations.

MR. PEDERSON: And to your knowledge is that‑‑

would that be typical of other non‑contiguous systems? That

at certain times they do operate independently, and at other

times they kind of operate together?

MS. SECKLER: I would assume that that would be

the case, that they would have some kind of an emergency

operating contingency.

MR. PEDERSON: Would it only be under emergency

situations? Or could there be a circumstance where we've

got non‑contiguous systems that are actually operating

together? Are you aware of anything along those lines, or

are any of the panelists?

MR. BLACK: I would just speak for Southwest, and

I certainly don't know what all the different LDC companies

have in their quiver for these issues. Our systems that

I've described to you are not interconnected in any way.

Clearly some of them are hundreds of miles apart, so they

wouldn't be. And even the two that appear to lay adjacent

to each other in Arizona were designed and built entirely

separately by different companies for different markets, and

they do not have an interconnect between the two in the

distribution side.

But I would think that it might be logical if you

have close lying places, as Ms. Seckler described, that that

would not be unusual. We don't happen to have that.

MS. SECKLER: And I guess I would add, too, that

where our systems are interconnected are basically where our

largest load areas area. If you look at the map down in

like southern Illinois, that's not connected to anything.

It's basically on its own. So other than it may have a

storage field, a company‑owned storage field or something

for emergency purposes; but where our three Illinois

utilities are connected are all in the basically central

Illinois area where the service territory somewhat overlaps.

MR. FARRELL: It is possible that you could have

some non‑contiguous systems coming into an interstate or a

major non‑interstate into one. That volume could be pooled,

you know, for supply purposes or under an agreement, but if

the receipt points or the delivery points from these

non‑contiguous systems into the major non‑interstate or the

interstate exceed 15,000 MMBtu per day, or whatever

threshold you determine, those volumes will be captured

under the proposal that's in front of us.

MR. PEDERSON: Yes, and I guess part of what I'm

trying to go through my mind is, I think one of the issues

that's been raised is we should treat non‑contiguous

separately. So there could be a circumstance, I think,

where neither of those systems meet the threshold but

together they might. And what I was querying is: Well, are

they operating separately, or not? Or is it kind of some

are, some aren't?

MR. FARRELL: Well certainly if I was a gatherer,

or if I was a producer that had non‑contiguous gathering,

certainly from an operations standpoint they're operated

absolutely separately. They're different physical

facilities.

The only way‑‑the only time that you would not

be, or once you‑‑once you deliver into the marketplace, the

major non‑interstate or the interstate, that is where they

become one, so to speak‑‑or possibly.

Now to the extent that they're going into

disparate systems, you don't have the physical operations

and you certainly don't have the contractual ability to

combine the two.

MR. BLACK: I would just add, and sort of a

follow‑up on what Mr. Farrell has said before, that in the

typical situation for Southwest whether these separate

operating divisions are interconnected or not, all of the

volumes that are delivered to us, to our facilities, will be

reported by the interstate pipeline because they're

delivered at known existing scheduling points on the

interstate pipeline.

So regardless of whether there might be‑‑even

though there isn't an interconnect in our distribution

facilities‑‑none of that volume will be lost in the

reporting function.

MR. PEDERSON: Thank you.

MS. COCHRANE: Did you have a question?

MR. STERLING: In addition to the physical

interconnection between these non‑contiguous facilities, do

either of you two companies engage in integrated operations

through contract paths or other sorts of transportation

means on interstate pipelines or intrastate pipelines?

MR. BLACK: Well speaking for Southwest there are

some transportation contracts that we hold on the interstate

pipeline in Arizona that may serve both the central Arizona

and southern Arizona divisions for transportation service.

But again, each of those will be scheduled to known

scheduling points by the pipeline and that volume will be

captured, either way. And they will be point by point. So

I can't even remember right now exactly which points are in

our southern Arizona division off the pipe, and which are in

the central, because we have like 27 of them in one pipeline

company, and literally hundreds of actual meters behind

those points, but they would all be reported either way.

MS. SECKLER: And for Ameren we may have more

than one non‑contiguous area on a single interstate

pipeline. So we may purchase one package of gas that gets

scheduled on an interstate pipeline that can be used to

various non‑contiguous service territories through the

control of the distribution system. But it's still just

scheduled to one central delivery point on the interstate

and through the distribution system. We move the gas to

where we need it to serve load.

MR. STERLING: Thank you.

MS. COCHRANE: Any other questions?

(No response.)

MS. COCHRANE: Great. Thank you very much. I

really appreciate the visuals. I always like talking to gas

people because they always bring their maps. It's a lot

easier to understand with drawings.

Thank you, very much.

Panel two can come on up.

(Pause.)

All right, thank you very much. This is panel

two which addresses how to account for high capacity receipt

point and delivery points where scheduling does not occur.

So with us today are Robert Young, Director of

Scheduling for Energy Transfer, speaking on behalf of the

Texas Pipeline Association; John Ellis, Senior Counsel for

San Diego Gas & Electric and Southern California Gas

Company; Bridget Shahan, Assistant General Counsel and Chief

Compliance Officer for Nicor Gas; and Michael Novak,

Assistant General Manager for Federal Regulatory Affairs,

National Fuel Gas Distribution Corp., on behalf of the

American Gas Association.

I don't know if, like the last panel did you guys

decide who might go first? Okay, that's fine. So, Mike

Novak.

MR. NOVAK: Good morning. I am Mike Novak from

National Fuel Gas Distribution Corporation where I'm the

Assistant General Manager within our Rates & Regulatory

Affairs Department.

For nearly my entire 25‑year career at National

Fuel I've been involved with some aspect of customer

transportation or another. This involvement included

responsibility for our Transportation Services Department

at a time when we designed and implemented our

transportation web site and scheduling systems. Nearly 50‑

percent of the annual throughput on the National Fuel

Distribution System is customer transportation and we expect

this number to keep on growing.

Today I am speaking on behalf of the American Gas

Association. AGA supports the Commission's market

transparency efforts that are designed to foster greater

confidence in natural gas price formation.

Where LDCs have information that would be helpful

to the market in this regard, it is not unreasonable to

expect that LDCs would make this information available,

provided that it can be done on a cost‑effective manner.

That said, it would appear as if some believe that scheduled

deliveries on LDC systems plays a greater role in market

price formation than is actually the case. I hope to be

able to shed some light on this today.

While LDCs have some similarities with intrastate

and interstate pipelines, LDCs are essentially distributors.

Even when an LDC provides a transportation service,

provision of such service does not morph the LDC into a

transmission provider. Whether an LDC is a statutory

obligation to serve, whether an LDC customer receives

bundled or unbundled service, the typical LDC customer

expects to be served.

LDCs operationally manage their systems to

service all customers with some limited exceptions that are

usually spelled out in tariffs that are approved by state

regulators.

As a general matter, LDCs do not consider market

prices when they determine how much gas is necessary to

serve the market on a daily basis. The expectation is that

the market is going to be served and, for the most part,

anticipated demand is going to be a function of weather and

historical load patterns.

Most receipts into LDCs are from interstate

pipelines. The amount of supply‑‑for example,

production‑‑connected directly to LDCs is relatively small.

In response to the amount of information required to manage

LDC transportation services, some LDCs have scheduling

systems and others do not.

These are the important factors in determining

whether LDCs have information relevant to market price

formation that is not available elsewhere, and the cost at

which that information can be provided.

Thank you.

MS. SHAHAN: Good morning. I'm Bridget Shahan of

Nicor Gas and I appreciate the opportunity for being here.

Nicor Gas, like most LDCs, has a reticulated

system. We have 96 receipt points from interstate

pipelines. We do not have any production directly connected

to our system. And we have 2.2 million delivery points,

mostly to residential customers.

Nicor is the provider of last resort to these

customers. And as an LDC, we wear two hats. We are the gas

supplier and we are also the system operator for our

transportation customers. We have approximately 15,000

transportation customers.

And 55 percent of the volumes that Nicor delivers

goes to bundled sales customers. 99.9 percent of the

volumes we deliver go to sales and transportation customers.

There's approximately about a .1 percent of the volumes

delivered to Nicor System that go to other LDCs or back to

an interstate pipeline.

Nicor has an annual delivery on its system of

about 500 bcf. Now Nicor also has two divisions within its

operations. There's the SCADA control room, which handles

the physical operations. It monitors the actual flow at

those 96 interconnects, and it is handling on a real‑time

basis the pressure. It is dealing with maintenance issues.

It talks control room to control room to other interstate

pipelines, or to the interstate pipelines or other LDCs.

And when there are issues they have to handle them

immediately.

The other division is the Gas Supply Department.

It is making sure that sufficient gas is scheduled to the

city‑gate. Now what they are doing is they are handling the

nominations, the schedules, and the confirmations. And for

our largest interstate pipeline supplier, which is Natural,

we have 75 physical interconnects but we have one scheduling

point for Natural, and Gas Supply is dealing with that one

central, or virtual, scheduling point.

Nicor then on its system, we have one Nomination

Cycle a day currently. What we do, the purpose of that is

to confirm what the shippers have scheduled upstream on the

interstate pipelines. Then we also use that information for

our billing purposes.

Now on a daily basis we know the scheduled

volumes that come into that central delivery point, and we

also know the actual volumes that go to that 96

interconnects. But as long as there are no issues or

problems on the system, they really don't have anything to

do with each other. It's only when there may be issues‑‑

let's say volatility.

Volatility could be weather. It could be supply,

force majeure, maintenance, it could be demand. There's a

lot of possibility for what volatility could be. And if we

do have that volatility, then Nicor has tools to use.

We have our No Notice on the interstate pipeline

systems. We have storage on Natural's system. We can go

out in the Daily Market and buy if we think we need to get

more gas to our city‑gate. Then we have OVAs for monthly

reconciliations with the interstates.

That is what we can do upstream.

Then on our own system, if we still have issues,

our shippers have a lot of flexibility because we have on‑

system storage. And they have a certain number of days of

storage every year that they can use. So if they come up

short with an imbalance or too much, they can play with

their storage to correct their imbalance on a daily basis.

If for some reason they don't have any gas in

their storage, they can buy the gas from Nicor at its PGA or

Gas‑‑I think it's greater, PGA or Gas Daily. And if they

brought in too much, they can also park it. And all of that

is based on our Illinois‑approved tariff of what their

contractual rights are and their tariff rights are of how

they balance once they get on our system.

And then finally, Nicor also has the ability to

restrict and put OFOs, or critical days on its own system if

there really is an issue that is not being addressed by the

shippers. Usually there's a notice put out first like:

Well, we see warm weather coming. You may want to back off

on bringing gas in.

And if it doesn't happen and we have to do

something, then we will do something. Let me see if I've

covered all of what I wanted to say. Basically I just

wanted to say that also the transportation customers are

scheduling on the interstate to a virtual point. And then

they are scheduling once they come onto our system to what

we call pools, which are virtual points.

And those pools are really designed and created

by that transportation customer. That transportation

customer could be a franchised store that has multiple

locations around the state. So it has multiple meters in

its contract, and that's its pool, and it is bringing in a

certain amount of gas for those meters.

Or a transportation customer can have multiple

customers of its own. And again in that contract it is

going to have all those meters of those customers. And they

are just nominating into our system to a pool. And they are

really nominating to their own contract. And that is how we

do the end‑of‑the‑month billing reconciliation.

They have nominated to their contract. End of

the month they figure out what their customers or those

meters actually took, and it is reconciled.

So thank you.

MS. COCHRANE: Thank you very much.

MR. ELLIS: Good morning. My name is John Ellis.

I am an attorney for Southern California Gas Company and

San Diego Gas & Electric Company. Thank you for the

opportunity to come here this morning and follow up on

issues and concerns the Staff raised in the Request For

Rehearing.

I have some presentation materials I will try and

talk to. The second slide is entitled Scheduling to the

city‑gate. Much of what I have to say will be similar to

what you just heard from Mr. Novak and Ms. Shahan.

The first point is that over 90‑ percent of the

gas scheduled in the SDG&E and SoCalGas System and the PG&E

system comes from interstate pipelines where scheduled

quantities are already posted. The point here is that any

requirement of posting of information of receipts would be

duplicative to what is already available.

The second point is that both SDG&E/SoCalGas and

PG&E already post all scheduled supplies into and out of

their systems and any scheduled supplies into and out of

their storage fields. Those area available on our web

sites, on our electronic bulletin boards. The addresses for

those web sites are actually stated in footnote eight of the

Request For Rehearing filed by the American Gas Association.

And I believe Mr. Peterson of your staff has access to the

password‑protected web site, and I believe a member of Dr.

Quinn's staff also will have that shortly.

The third point is a function of editing a

presentation while traveling and having access to the

presentation by Blackberry‑‑the point is that both

SDG&E/SoCalGas and PG&E already post aggregated on system

demand information. This would be an aggregate of the

receipts of the different interstate interconnects from

California production. The question that's asked by one

commenter is: Is this true for SoCalGas? The answer is:

Yes, it is.

The next couple of slides are maps of the

facilities of PG&E and SDG&E/SoCalGas. These were exhibits

to the Request For Rehearing. They just give a graphic

representation or a pictorial representation of where we are

receiving supplies from, the interstates. For PG&E that is

primarily at Malin on the California/Oregon border, and

Topock at the border between California and Arizona. And

also from Kern River.

The second slide is‑‑

MS. COCHRANE: Can I ask you a quick question

while we're one it?

MR. ELLIS: Sure.

MS. COCHRANE: What do you consider your city‑

gate?

MR. ELLIS: The city‑gate is behind the border.

MS. COCHRANE: On the map, where would you

consider the city‑gate? How would you define that?

MR. ELLIS: The city‑gate is a virtual point. It

is not a specific physical location. It is a point at which

pooled supplies can be traded, received in and out of the

system, but there is no one physical location.

MS. COCHRANE: I just wanted to clarify that.

MR. ELLIS: The next slide shows the five receipt

point zones for Southern California Gas Company and SDG&E.

These are a function of the Firm Access Rights Program that

went into effect October 1st, 2008. There is an allocation

of Receipt Point Rights through these zones that customers

hold, and these are the paths into the system into the city‑

gate for Southern California Gas Company and SDG&E.

Again, the major receipt points are on the

California/Arizona border with the El Paso Natural Gas

Company System and the Trans Western Natural Gas Company

Interstate System, and then from Kern River, and then also

from California Production in the Line 85 Zone and the

Coastal Zone.

The next slide addresses the issues of‑‑begins to

address the issues of concern in Order No. 720. It's

Scheduling Downstream of the city‑gate.

The first point is that the majority of gas

scheduled into our system is scheduled through the city‑gate

and through city‑gate Pooling Accounts. Some gas is

scheduled directly beyond the city‑gate, but most comes

through Pooling Accounts at the city‑gate. There is a

Nomination Model at Slide 10 of this presentation that will

show the‑‑that shows the Scheduling Model.

So for SDG&E/SoCalGas after gas is scheduled

through the city‑gate, it is then scheduled one of three

places: customer pool accounts, storage accounts, or back

off the system. Currently for SoCalGas and SDG&E there is

only one location to schedule back off the system and that

is to the PG&E System. We have an application to the

California Public Utilities Commission for authority to

confirm scheduling back to interstate. That authority has

not been granted to date. We expect it to be granted, but

currently the off system delivery for SDG&E/SoCalGas are

only back to PG&E.

The last point‑‑and this is where we begin to get

into the issue that has been addressed already by Mr. Novak

and Ms. Shahan‑‑SDG&E and SoCalGas have no requirement or

operational need to have gas supplies nominated and

scheduled to specific end‑use delivery points.

Turning to the next slide, we have approximately

1,000 end‑use customers who participate in our

state‑Commission approved transportation Program; and an

estimate 110 end‑use facilities which have a delivery

capacity of grater than 15,000 decatherms a day.

As I understand it, the intent of Order No. 720

is to gather information with regard to end‑use facilities

of a certain size. The first point here is that these end‑

use facilities typically are going to be served through

pooled accounts, and there is no price formation downstream

of the city‑gate.

Turning to the next page, this describes the

pooling of the accounts by which these end‑use facilities of

a certain size would receive their gas supplies.

Participants in our transportation program are

assigned a customer account for nominations and scheduling

purposes.

A single customer account can represent one or

numerous end‑use facilities with varying types of end uses.

And balancing of scheduled volumes and deliveries

by customer account is monthly, not daily. I think that is

the limitation that produces the result that the information

that the Commission seeks to obtain with regard to these

end‑use facilities of a certain size is not really available

from the system operators of the LDCs.

Turning to the next slide over, over 90 percent

of those 10,000 customer accounts are aggregated into

Contracted Marketer accounts. Those are pools. A Marketer

acts to pool the accounts of individual customers. And over

90 percent of our 1,000 customers are served through a

Marketer Pool.

The marketer assumes the monthly gas delivery and

balancing requirements for their group or pool of end‑use

customers.

Marketers nominate to the pool account, not to

specific end‑use customers, not to specific end‑use

facilities. The marketers are not required to nominate any

quantity on a daily basis, and the nominations could vary

from zero to any amount and therefore bear no real relation

to expected consumption or actual consumption at a facility

on any given day or period of days.

I will note that for the PG&E System I believe

there is a nomination to an end‑use facility but the

function of the nomination is not any estimate of actual

consumption. It is a numerical convention to allow PG&E's

scheduling system to operate. The numbers that are posted

to end‑use facilities by marketers can be arbitrarily

assigned.

For example, a marketer may have the ability to

nominate 100 units. It may nominate 10 units to one

facility, 20 to another, 30 to a third, and the balance of

40 to a fourth, and none to the other six. It really bears

no relation to the actual consumption or expected

consumption at the facility.

And again for SDG&E/SoCalGas we do not even have

nomination down at the individual‑facility level.

The conclusion is that requiring of posting of

scheduled volumes to end‑use delivery points on the

California LDCs' systems will not facilitate price

transparency in markets for the sale or transportation of

physical natural gas in interstate commerce. That is

because, again, on the SDG&E/SoCalGas Systems we don't even

have nominations to end‑use delivery points, and the

nominations on the PG&E system are arbitrary and do not bear

any direct relation to actual or expected consumption.

The next slide is a Nominations Model. I'll just

discuss it briefly. We show at the top the two sources of

gas supply into the system, either supplies from interstate

pipelines or approximately 7 percent of the supply is from

California producers.

On our system those come through a Receipt Point

Access Contract. That's the RPAC. From there they can

typically go one of three places: Customer Pool, city‑gate

Pool, or Storage. Or they can go directly to the off system

delivery, OSD, which currently again is only PG&E for our

system.

The last three slides are answers to the

questions posed by Staff as part of the notice of this

technical conference.

The first question is: Is there some rule of

thumb to identify points at which advance notice of receipts

and deliveries is required for operational purposes?

I think in looking at these questions I

appreciate that you recognize the limitation on the validity

of the information that is typically available to LDCs on

scheduling to end‑use facilities, and these questions ask,

don't you have some operational need to have this

information? Generally the answer is: No.

So this specific question: Is there some rule of

thumb to identify points at which advance notice of receipts

or deliveries is required for operational purposes?

The answer is: Not for deliveries on the

SDG&E/SoCalGas and PG&E Systems. We don't have an

operational need for advance notice of deliveries to end‑use

locations for individual entities in order to plan our

system operations. We receive information from the

interconnecting pipelines, and we have our own information

regarding historical consumption patterns, weather

information. We may have information on specific planned

outages, and information from the California ISO, and that

is what we use to plan daily system operations.

The second question: How do companies without

scheduling information address the risk of demand

volatility for large‑scale consumers receiving unbundled

service?

Our response is that our systems are designed and

built to criteria defined by our State Commission, and we

recover the costs of those facilities in rates paid by our

customers, including transportation rates, paid by, among

others, the 110 or so customers of the size that Order

No. 720 inquires about.

The systems are designed to manage hourly and

daily flexibility‑‑I'm sorry, hourly and daily volatility in

demand primarily through the use of storage. And this is in

contrast to interstate pipeline systems which are designed

to move gas from point A to point B on a uniform average

daily basis.

Your third question was: How do pipelines

reconcile nominations with actual flows at pooled points?

For our city‑gate we reconcile by each Nomination

Cycle. Your nominations have got to be confirmed or else

they'll be cut.

But past the city‑gate, this is done on a monthly

basis. Again I refer back to the point I emphasized

earlier, and that is: balancing is monthly, and it is done

at the pool level. It is not done at the individual

facility level, and it is not done on a daily basis.

Therefore, we have no need for scheduling down to the end‑

use delivery point on a daily basis, and we don't have that

information available.

That concludes my initial remarks. Thank you.

MS. COCHRANE: Thank you very much.

Mr. Young?

MR. YOUNG: Good morning. I am Robert Young. I

am Director of Scheduling for Energy Transfer, and I wanted

to go through some of the questions you had.

We also had a proposal on some design capacity

that I wanted to get to. But before I do that, it seems

like the common theme that everybody has been talking about

so far is Mainline Receipt Points are what we need. Because

there's a lot of gathering systems out there who have small

wellheads. You have city‑gate, LDCs, you have small

deliveries downstream. But all of that gas seems to be

captured at the Mainline Receipt Point into an interstate or

into an intrastate. So, where you could have duplicative

data if you go back to the wellhead or to the city‑gate. So

capturing that information at the Mainline Receipt Point

seems to be something that I've seen or heard so far.

Going through the questions on is there some rule

of thumb, I concur with Mr. Ellis's comments. What our

response would be is: It depends.

Some pipelines actually do have nominations at a

wellhead. I think very few, if any, LDCs have nominations

at their ultimate delivery points. But it seems like

everybody does aggregate at a Mainline Receipt Point. So

they would‑‑some pipelines, if they have wellhead flow,

sometimes just manage the tailgate into the downstream

pipeline. That's where the nominations come.

Then there's either a monthly, sometimes daily

process that those gatherers would have with their

customers.

How do companies without scheduling information

address the risk of demand volatility?

Most of the times systems are designed to take

that into account, but for the most part the Gas Control

shop will look at linepack. If we've got deliveries to a

bunch of city‑gates, there will be nominations to the

virtual meters, the pool meters, whatever you want to call

them, the point where all the gas is supposed to be

delivered to that market point.

There might be hundreds of meters that come in

that we might have SCADA on, we might not have SCADA on, but

a gas controller will know a scheduled number that he's

expected to see for an area for that day.

They'll look at that number. They'll look at

their SCADA screens. You'll see overpulls or underpulls,

and you'll see linepack go up and down, and that's where the

gas controllers can manage the pipeline, whether they have

storage, if there's nomination cuts in subsequent cycles, or

whatever we need to do.

But for the most part, the gas controller will

look at it and he'll tell you on a 5:00 p.m. in San Antonio

in the summertime, 5 o'clock your linepack is going to go

down because everybody comes home, turns on their air

conditioners so the LDCs pulling all the gas off the pipe.

But they manage that throughout the day, and that's where

they have the 24‑hour nom. They'll pack the line, try to

stay within the parameters and everything kind of works.

It's as much an art form as it is a science.

Then how do pipelines reconcile nominations with

actual flows at pool points?

Again, a lot of times that is a monthly process.

There are a lot of virtual pool points, and the reason

there's virtual points is, when you have shippers and

customers who you might be delivering to hundreds of points,

the simple fact of nominating individually to those points

is not manageable on a daily basis.

So if you'll have a customer who is scheduling

gas to those hundred points, they just give you a nom for

one, we'll actually get measurement data at the end of the

month, sometimes daily, for those points but you allocate

that nomination back to those points, or you aggregate those

points back up to that nomination.

So again it is more of a commercial tool, and it

is not really necessary to have people nominate to

downstream delivery points, certainly at LDC delivery

points, and certainly from gathering systems where all that

gas is brought in by one party. There's no reason to have

to have a nomination we feel at this point.

Then finally, one of the things we have struggled

with a little bit is in terms of the posting requirement is

the definition of "design capacity."

Part of the issue is, when we say "design

capacity of 15,000," I'm not an engineer but I've talked to

lots of engineers, and a rule of thumb could be:

A 4‑inch meter run could actually flow 16 million

a day. If you look at most of your 4‑inch meter runs at the

wellhead, they're not going to flow more than a couple

million a day. So in that case, if we use that as the

design capacity, we're going to have postings of a 16‑

million capacity with throughput of 2 to 3 million, which

will show available capacity of a lot more, which is really

not the case.

A proposal that we have‑‑this is not necessarily

in regulatory text, but just to get the idea‑‑we would like

to change it to say:

A major non‑interstate pipeline must post at all

nominated, receipt, and delivery points with 10‑day

nonconsecutive average peak flow of 15,000 MMBtu per day

during the prior calendar year, to be updated every April

1st. A such points the pipeline will post such 10‑day

nonconsecutive average peak flow as capacity at the point

rather than design capacity, and available capacity at the

point will be determined based upon capacity minus scheduled

volume.

What that does it, if you take an average flow at

metered, which is realistic of what's going to be produced,

if you define that as the "capacity," you'll have a better

feel for what physically comes along, what the real capacity

is, rather than an engineering capacity which is always

going to be a lot higher than what a meter will physically

do on normal days.

MS. COCHRANE: Could you just repeat that again?

You appear to have a definition, so I just want to make sure

we understand.

MR. YOUNG: Okay. A major noninterstate

pipeline must post at all nominated receipt and delivery

points‑‑that's just every point we schedule on, and that

would be in cases where we have pool meters we would post at

the pool meter level rather than the individual points

behind it‑‑with 10‑day nonconsecutive average peak flow of

15,000 MMBtu per day during prior calendar year.

What that means is, go back a year. Look at all

the points. See‑‑take the top 10 days for the last year.

If the average of those is more than 15,000 a day, post

that. And we had a timing of posting that yearly, and we

could update that as necessary.

And at those points, at such points pipeline will

post such 10‑day nonconsecutive average peak flow as

capacity. So rather than a design capacity, that would

become your capacity. You would compare that to your

scheduled record that are nominated every day.

The available capacity would then be the

difference between the two. And when you do that, based on

the diagrams that we've looked at, especially if you look at

Mainline Receipt Points in the diagram that was presented

before, you have all these wells upstream of a plant. Most

of those, it could be 4‑inch meter runs, but they probably

aren't going to flow more than 15,000 a day.

But at the Mainline Point where it comes into the

system, it certainly will be 15,000 a day. And if it's not,

it's just a very small plant.

You post the volume at that point, and then you

compare that to your schedule everyday. And that is your

capacity. So in that case, you are capturing the gas coming

into the market at that one receipt point into a inter‑ or

an intrastate point, rather than multiple points upstream.

So I would envision, based on the example, rather

than having all the gathering points, but 100 gathering

points with a design capacity of 16,000 a day flowing from

100 to 5 million a day, you would have one point that could

be 100 million a day with a design capacity and scheduled at

that point, because that's where most people do their

scheduling anyway.

And even if people schedule at the wellhead,

there is always scheduling at some type of Mainline Receipt

Point, whether it be a virtual or an actual point.

And I think that covers everything.

MR. NOVAK: Excuse me, I have a process question.

I didn't know whether we would be going through question by

question, or what you would like to do at this point,

because I have my rule of thumb also. Would you like that

now? Or do you want to go through‑‑

MS. COCHRANE: Sure, because I was going to ask

you how you were going to get this into the record. But,

yes, please go ahead.

MR. NOVAK: Okay. On the Rule of Thumb for LDCs,

this question really has to be broken into two questions:

One for receipts and one for deliveries.

Receipt information is far more critical because

the operational assumption is that deliveries will be made

no matter what quantity of gas is received into the system.

The deliveries will be based upon customer demand and in

nearly all cases not upon what the LDC receives into its

system.

Pipeline no‑notice service, or in some cases on‑

system assets‑‑for example, line pack and in a few cases

storage‑‑are used to supplement or balance the difference

between what is received and what is delivered‑‑which is

the market demand. This is essentially how LDCs "back stop"

the system.

Keeping in mind that (1) most gas is received in

LDC systems at the city‑gate, and (2) that both LDCs and

marketers serving LDC customers nominate gas on pipelines,

LDCs officially learn how much gas is being received for the

next gas day at 4:30 p.m. Central Time for the NAESB

Standard.

Some LDCs with their own scheduling systems may

have some advanced notice depending upon their own

nomination timelines, and LDCs with or without scheduling

systems‑‑to the extent that they're actively engaged in the

pipeline confirmation process‑‑can improve their advance

notice also.

Of course all of this relevant information

regarding the receipts into the LDC systems at the city‑gate

interconnections with interstate pipelines are already

available from the interstate pipelines.

Depending upon the LDC system configuration,

advance notice at some city‑gate receipt points may be more

critical than others. And I think that Vonda started to

touch on this in her presentation. You look at the size of

different markets, whether they're contiguous,

noncontiguous, our terminology is "load pockets." You need

to look at the number of options. Advance notice of sole

sources into load pockets is probably to be of more critical

importance.

Scheduling of deliveries is generally of much

less importance because the LDC systems are designed to

distribute the receipts that flow.

The more critical problem is making sure that the

right amount of gas shows up at the receipt points. LDCs

project load for their bundled customers and in particular

for customer choice programs for unbundled customers.

Suppliers often receive instructions prior to the

nomination deadline on what quantity should be delivered to

the LDC. These projections are based upon historical load

patterns and weather forecasts. It is not really a matter

of looking at market pricing to determine whether gas should

be received and whether the customer delivery should be

made.

Larger industrial and commercial customers

sometimes have more latitude in determining what quantity of

gas is necessary to serve their load.

In some cases this flexibility may be associated

with a service that limits the customer balancing rights

and/or necessitates a point‑to‑point nomination‑‑a receipt

to a delivery point.

Nevertheless, in most cases an LDCs do not

require a nomination to a delivery point because (1) the

customer's physical location is not going to change; and (2)

the customers may be pooled for nomination purposes with

other customers that are served by the same supplier.

In this latter case, the LDC is more concerned

that the total pooled receipts match the total pooled

deliveries and not with any particular transmission path.

Please keep in mind that if the LDC doesn't require a

nomination to the delivery point, it doesn't have the

delivery point scheduling information.

On the issue of addressing the risk of demand

volatility from large‑scale consumers receiving unbundled

service, generally this is done through service and rate

design.

Balancing calculations can be performed on a

daily or a month level. In either case, it's a matter of

allocating the costs of assets used to balance to those that

require balancing. This is a critical matter in the state

regulatory environment. An interrelated concern is to avoid

having one group of customers subsidizing another.

Note that for customer pools, balancing is

usually at the pool level‑‑in other words, total receipts to

total deliveries rather than matching particular receipts

to particular customer deliveries.

Finally, many utilities use SCADA systems to

monitor system flows and have OFO authority to tighten

transportation service flexibility if it becomes necessary.

Lastly, on reconciling the actual flows at pooled

points, many LDCs incorporate pooling into their scheduling

rules. This can be done for receipts‑‑at city‑gates or for

On‑System Production‑‑or deliveries‑‑groups of customers.

Pools can be organized geographically, by service

characteristics, and/or at the supplier's discretion. It is

really a territory‑by‑territory determination.

For most LDCs, the reconciliation is a monthly

accounting calculation but depending upon the service design

can be a daily calculation.

Keep in mind that service designs and changes to

service designs need to be approved by state commissions.

Whether a daily or monthly reconciliation, flow differences

can be balanced with physical assets, cased out, or carried

forward to a subsequent day or month.

Note that even under a monthly reconciliation,

LDCs may monitor daily activity to make sure that there's a

relative balance within a tolerance range.

Thank you, very much.

MS. COCHRANE: I just wanted to clarify for

Mr. Ellis why I asked that question about city‑gate. In

your Rehearing Request you suggest that posting could be at

the interconnections with the interstate or at the city‑

gate, and I just wanted to clarify that that means two

different things. That your city‑gate is not at the

interconnection with the pipeline.

MR. ELLIS: That is correct. They are two

different places. And I think for SoCal Gas the more

correct statement would be On‑System Receipts versus

deliveries to Storage. And for PG&E's system, they have a

number they can post at the city‑gate. For ours, let me

just say it could be traded, the amounts scheduled to a

city‑gate can be traded, can be scheduled in and out, and I

think the more accurate measure would be On‑System

Receipts.

MR. REICH: Ms. Shahan, in your hearing request

you say Nicor has 400 meters that meets the 15,000 limit,

but you only schedule about a dozen?

MS. SHAHAN: Yes. And actually I can clarify

that even more. Those entities are not scheduled to their

delivery point meters. They are restricted in scheduling to

specific receipt points.

So they would not be able to use our CDP with

Natural because those entities‑‑we have some very large

refineries in our service area, and then we have some

electric generators, and because of their load, and they are

close to certain pipelines, they are required to bring it in

off of that pipeline and schedule to that receipt point into

our system.

But basically it's the receipt point. It's not

their delivery point.

MR. REICH: Just to clarify, so their

activity‑‑if they have volatility in their demand, that

would show up in a nomination on the pipeline?

MS. SHAHAN: Well, no, we do balancing for them.

So they have nominated it on the pipe, the pipe is confirmed

and scheduled a certain amount. If something happens during

the middle of the day or the night and they've changed in a

later nom cycle on the pipe, we don't have a later nom

cycle. They're just out of balance and we will help them

with our storage. They have storage rights under their

contract.

MR. REICH: So for Natural‑‑you said Natural was

your‑‑

MS. SHAHAN: It's one of them.

MR. REICH: ‑‑your main pipeline‑‑

MS. SHAHAN: Um‑hmm.

MR. REICH: So if you have one of these

facilities that can only get gas off of Natural, what does

that look like? What does, you know, one day where they

have high demand versus one day that they have low demand

look like to Natural versus what it looks like to you in

terms of planning?

MS. SHAHAN: Well, actually they aren't on

Natural, I will say that. They are on some of the others.

We are on seven interconnects. And they‑‑if they have

changed their mid‑day or late nom, we still have them

scheduled for their morning nom. And again, whatever they

bring in and the pipe has proved, or confirmed, they get to

play with that difference with their storage.

MR. REICH: And are these‑‑these are

transportation, all transportation customers?

MS. SHAHAN: Yes.

MR. REICH: So you're just, you're providing

transportation service but also balancing service?

MS. SHAHAN: Yes. All our transportation

customers do have a certain amount of storage rights under

our Illinois Tariff.

MR. ELLIS: That's the same situation for our

system, too.

MR. REICH: You anticipated my next question.

Also, Ms. Shahan, in your‑‑in the Rehearing

Request you talked about your eight storage facilities. Can

you talk a little about how those are scheduled, or planned

for on a daily basis?

MS. SHAHAN: Again there's the two different

worlds at Nicor. There's the SCADA control room that's

watching the pressure and making sure everything is

copacetic, working. That is really behind the scenes of

what transportation customers are doing and what they're

scheduling.

They are‑‑if it's summertime and they want to

fill their storage, they just nominate to storage. They

don't have rights in different fields. They're scattered

around our service area. And they nominate‑‑and it doesn't

really matter what pipe they bring it in off of; they're

nominating to virtual storage, and we make sure it gets

where it needs to go.

MR. REICH: So it's an unbundled storage service

where these customers, their gas is in storage as opposed

to, or in addition to buying gas from you, if necessary‑‑

MS. SHAHAN: Correct.

MR. REICH: And with SoCal?

MR. ELLIS: Same situation.

MR. REICH: Chris?

MR. PETERSON: The model that seems to occur on

many of these systems is large‑volume receipts are scheduled

either by you or in some cases maybe by others into

substantial city‑gate receipt points. And then things vary

from there in terms of the latitude that your customers have

to then schedule that gas on non‑major interstates of

different sizes.

But generally what would help us understand is

that‑‑I mean, some of you have large‑‑you have generated

assets on your systems. They can consume 85 million to 170

million a day at typical 7000 heat rate combined cycle

plants. These loads can change quickly depending on weather

conditions.

So if you're just scheduling at the pool level

and you're truing up at the end‑use level on a monthly

basis, how are you managing congestion on your system? How

do you make sure that the pipeline system integrity isn't

being violated?

Because there's this disconnect in that, on the

one hand at certain points things are happening daily,

there's SCADA, you may even be looking at things at one

level hourly, maybe even five‑minute intervals, or whatever,

yet on the end‑use side you're only looking at deliveries

maybe on a monthly basis.

So how do you reconcile this? How do you make

sure how you manage congestion? How do you make sure

customers are getting what they're entitled to commercially

and in their contracts? That would help us understand sort

of the commercial and operational challenges you might have

in comporting with different ways we could go with this

rule.

MR. ELLIS: For SoCalGas/SDG&E, as I heard the

question: What do you do when things start to get out of

balance? What kinds of things can you do to manage these

situations?

And, you know, we have operational flow order

authority if the situation‑‑if the system situations require

it. And in that case, balancing is daily.

For SoCalGas/SDG&E currently, the OFOs are for

pack conditions only. We no longer call OFOs for draft

conditions. For pack conditions, the typical response to a

pack OFO would be to immediately stop scheduling.

But the general question you asked, how is the

volatility managed other than monthly, it's managed daily on

an OFO basis if the conditions require it. And in that case

balancing is daily.

MR. PETERSON: And the OFOs you might apply,

would those be system wide? Are the customer‑specific?

That varies on interstate natural gas pipelines too

depending on who is leaning on the system, where it is. How

does that work?

MR. ELLIS: I believe ours is system wide. That

is subject to check.

MR. REICH: Can I follow up?

MS. COCHRANE: Mike would like to‑‑

MR. NOVAK: Yes, I think it is also a case‑

specific situation. And Bridget started to touch on the

operating world versus the accounting world.

In the operating world, you are probably going to

have a communication from the operator of the electric

facility to the gas control room, hey, we're going to be on

in a few hours. It has nothing to do transactionally; it's

just the load is coming on. So that is going to tell the

gas operator, start packing the system.

The nominations will come in. They'll be

balanced. I mean, again it's a service design and probably

location of facility type of situation. The OFO authority

can come into play. But there won't necessarily be a one

common rule that fits every single situation where this is

going to come into play.

MR. YOUNG: One thing, in terms of the process a

lot of times you'll have pipelines‑‑you know, pipelines will

have their gas control center. You'll have the LDCs who

have their gas control centers. The mainline delivery

points often have balancing agreements between the pipe and

the LDC.

So there's a process at the beginning of the

month to estimate how much gas you're going to need. So the

LDC customers will come in and say this is how much I'm

going to need this month. They'll secure gas. They'll

either buy it from shippers, have their own transport

agreements on the pipelines, and they'll nominate to that

mainline delivery point.

Then as things happen, you know, that estimate

assumes they're going to be able to cover everything with

their line pack. They've got enough for the day to cover

everything.

If there are overpools for some reason, the

pipeline is going to see that there's gas being overpooled.

There's communication between the control centers every day.

If something has to happen, there's communication. The gas

controller on the pipeline will say: What's going on?

You're supposed to take 50 million and you're taking 80

million.

Then the response could be: Well, we just got a

problem here. Can you help us out? Or we're going to get

back down on rate. Or there needs to be a new schedule at

that mainline delivery point to bring more gas in because

the pipeline has to manage that same type of thing with all

their delivery points.

So, you know, without getting into all the orders

and the postings on a daily basis, that's just part of the

gas controller's job to know. But there's a lot of work

that gets done into that schedule director at the beginning

of the month. So they're not just scheduling a number and

letting it flow; they're doing some analysis and estimates

of what they're going to need for the month, and they're

usually pretty close.

And then on a daily basis, the gas control

centers work with each other to make that happen.

MR. PETERSON: If I could follow up on that, so I

guess one thing that would be helpful for us to know more

about, too, is if your main concern is that receipts and

deliveries at the city‑gate pooling points, or main entries

in your system match on a daily basis, then how do you

allocate volumes of gas to your large customers that sit

behind your gates?

How does that work? If it's not a daily nom

process, how do you effectuate that commercially? And I

think what you were saying is some of this is, you look‑‑is

some of this done on a monthly basis where, okay, it's not

done daily but a generator may say, hey, I anticipate

needing 50 million a day on average. They let you know

that. And then you set up your system that way? Or how

does that work?

MR. YOUNG: I think one of the reasons there is

not a daily allocation is because most of‑‑and I'll let you

guys correct me where I'm wrong‑‑but on the LDCs, most of

those delivery points serve a customer. So you don't have

multiple allocations at an ultimate delivery point.

So whatever flows to that ultimate delivery is

allocated to a customer. So they'll have a pool of all of

their gas. So if they have 100 meters, those 100 meters all

aggregate to one customer. So the customer then can

schedule that one number, and the LDC's responsibility is

just to make sure the deliveries get there.

But then there's a post‑month allocation, if you

will, saying here's the measurement, here's the volume that

flowed at each of those points. You sum it up to that

scheduled record level, and that is your imbalance, if you

will.

MS. SHAHAN: And I'll just add that, you know,

these customers on Nicor's system have contractual

limitations. They have MDQs that they're supposed to stay

within. And if they haven't, then they will either have an

authorized overrun, or an unauthorized overrun, but they

again are nominating to their pools.

They may have one meter that could be a

transportation customer that is just a refinery and he has

one meter. Or it could be a supplier/marketer type of

transportation customer that has a thousand customers behind

him. And all those meters are on his contract, and that is

his responsibility to figure out‑‑he's going to get charged,

and then he's going to have to figure out with his customers

what deal he has negotiated for them for their supply.

So it is still an end‑of‑the‑month issue. And as

far as every day, we are looking at there's lots of

forecasting that goes on. Constant forecasting and revising

the forecasts because of the weather as much as any other

volatility. But market demand can also, and supply

operations or force majeure can affect those too.

But the control room has plans and is watching

not just daily, but speaking multiple times during the day

to other control rooms just to make sure everything is

working and going all right and they don't see any issues

coming from upstream toward us.

So it is an art, and it is a constant

communication.

MR. YOUNG: I mean, as an example, if you

had‑‑you know, I'm the pipeline. I'm delivering to an LDC.

It could be either a nomination at our interconnect point of

100 million. Then that's there for the month.

Then one day all of a sudden 140 million is being

pulled off our system because they need some gas. Well the

first thing I am going to see as a gas controller is we're

going to call and say, what's going on?

If it's an anomaly, they say, well, the

temperature's just raised real high, there's some anomalies

today, you know, can we go out‑of‑balance for the day?

Well then my response could be: Sure, but you

need to nominate more for tomorrow because I can't prop that

up. And that's where the nomination process at the mainline

delivery point would happen. They would identify the people

who were overpooling. They would have secure transportation

on our pipes so that tomorrow that nomination could be 140

to meet that pool, or maybe 160 to meet the pull of 140 so

that I can get paid back for the gas they pulled yesterday.

So again, it is more of an art with some science

mixed in.

MR. NOVAK: Even for pools from customer‑choice

programs where we may be given a different quantity

instruction every single day of the month, obviously the

meters you might have with 20,000 customers in a particular

supplier's pool, we aren't doing a daily comparison of how

much they delivered to how much the customers used on that

day. We simply sum up all the customer consumptions, then

we sum up all the receipts that should have in at the

quantities on the days that we wanted, and then compare the

two numbers.

And then any balancing will take place not at the

customer level but at the supplier level between the

supplier and the utility.

MR. PETERSON: If I could follow up with

comments, Mr. Novak and Mr. Young, you both just made then,

it seems to me in the comments that have been made there may

be challenges in terms of disclosing on a daily basis

information that might be customer level on networks for

your companies or your members, but what I'm hearing though

is ultimately on a monthly basis because of invoicing,

because of billing, you do know ex poste at least how much

you are delivering to your customers in situations where you

don't know day to day, but because of the monthly billing

cycle you do ultimately know that. And that information is

available to you.

So on a daily basis you have information

available at some SCADA‑metered locations, major receipt

points, maybe even some major delivery points, but in

addition you do know this information at‑‑or you arrive at

information through allocation procedures or other true‑ups

and balancing adjustments for the end of the month for your

customers. Is that correct?

MR. NOVAK: That's correct.

MS. SHAHAN: I just have to clarify the question.

If you say "this information," there's the scheduled world,

and there's the actual flow world.

MR. PETERSON: Right.

MS. SHAHAN: So it's what are you asking for.

What actually flowed, we definitely know by the end of the

month, and maybe 15 days later by the time the bill gets

out‑‑

MR. PETERSON: Right.

MS. SHAHAN: ‑‑what we're charging end‑users for.

But‑‑or what their suppliers are charging, because we're

reading the meters, are charging the end‑users for.

But the scheduled, again, is these virtual

points. And part of the clarification Nicor asked for is,

if you want this information of what is scheduled into our

system to pools and points, please realize there is no

location information. There is no available capacity

information. There is no design capacity information

because they are paper.

MR. NOVAK: Let me amend my answer just a little.

It depends upon the meter at the location. For the large

customer, we're probably going to have daily measurement and

are probably going to know more quickly, and are probably

going to know an exact number that they used.

When we're talking about a residential customer

where I'm reading it once a month on a billing cycle, the

best I can tell you is what I think they used.

MR. YOUNG: And so I would say you do have

measurement data at the points, but to move that back to,

and compare it to the scheduled data, it depends on how

different pipelines do their allocation process at the end

of the month.

Some people will allocate to the measurement

meter so that you will have the month scheduled and

measured. In other cases those measurement meters are

actually grouped. So the measurement is at a group virtual

meter and you apply that to the nomination that was done at

that same virtual group meter.

So you would have to put it together or break it

apart if you wanted to go one‑to‑one, but not all‑‑either

gathering systems or LDCs would have a one‑to‑one

relationship at the end of the month. They would have

measurement at the end of the month.

MR. PETERSON: I've got one last follow‑on for

you, Mr. Young.

All of the companies we purport to cover under

this rule have some significance in terms of the size. We

increase the annual volume commitment by a factor of five,

going from the NOPR to the Final Rule, considering burden

issues and some of the reporting things that you all are

relating to us today.

But even within the continuum of the possible

market participants that would be covered by this Rule,

there could be a lot of variety in terms of information that

does exist already, currently, for example, PG&E and SoCal,

they have the Pipe Ranger and onboard systems, somewhat

unique for LDCs to actually have something, you know,

somewhat like what interstate natural gas pipelines offer.

I suspect there are other companies, maybe TPA

members, that are very large companies, many of which might

be much larger even than standard interstate natural gas

pipelines, that may have a richness and robustness in terms

of the amount of information they collate each day already,

and how they solve their networks each day.

And there are these ‑‑ and there may be other

systems that may be smaller, that use the city gate model

where they are just kind of measuring what is coming in, to

like a handful of major city gate points, and then from

there, it's kind of a pool, and then from there, there may

be different strategies in terms of how you allocate that.

Can you speak to, you know, representing TPA and

the different companies you account for, can you give us

some insight as to the complexity of information, what

exists now, that's already being collated, how that

information is used, and how that might work?

MR. YOUNG: Well, there is a variety, and when

you talk ‑‑ you know, you hear the word, "pools" or

"aggregation points," and I think the issue that most people

have, is the level of detail at either the initial upstream

wellhead point, or the final downstream delivery point.

The one consistent point, I think, that

everybody probably has, is a mainline receipt point or a

mainline receipt or delivery virtual point. And gas is

scheduled at that point.

Even pipelines who schedule at the wellhead, they

will also schedule at the delivery point, into an

interconnect at a pipeline, an intra or interstate pipeline.

So the consistency, in my mind, would be at that

point, so you could have kind of common ground for

everybody, and then you don't have the burden of LDCs having

to figure out, well, how do I get all these thousands of

meters to compare to a scheduled record, when I don't have

it?

I think that's the issue that most of the

pipeline companies have. You know, from an energy transfer

standpoint, we've got receipt points coming into our pipe,

people nominate on those, and if they are more than 15

million a day, those will be posted.

But if we have a point where we're aggregating

hundreds of meters, we have one set of pipelines where gas

comes in, it's purchased; it's all at a ‑‑ there's really

not a nom, because we just know what we do, estimates of

what we think is going to be out there, but we don't really

nominate this gas that we're buying.

So there's really not a nomination that we can

look to. We'd have to create that at the end of the month,

or daily, for reporting purposes, but we do have that data

downstream at the mainline receipt points and the delivery

points, where we can provide that data.

And it's 1:1, if you will. There might be some

cases where you have to group, when you do the reporting, if

you have hundreds of those points, and we schedule at the

virtual point, then the design capacity or the capacity at

that virtual point, might have to be the sum of those meters

that were upstream of that.

But I think that could be a designation that each

of the companies could make, and some people could have the

upstream, other people wouldn't, so, you know, some

companies pool one way; others pool another. But the

consistency is that scheduled virtual point and how do we

report capacity at that point?

MR. ELLIS: I wonder if I could speak to that

question? As I heard, Mr. Peterson, you're asking, what

information is available.

I think I would begin by saying that we look at

what information is of value, that you've got posted

information at a level that we believe is of value.

If you turn to Slide 4 in the presentation

materials, that's the map that shows the receipt point

zones. You go on our website today, you'll see, for each of

these receipt point zones, with the amount of capacity

available, you can see how much is being used, and,

therefore, how much is available at each of these locations

on a receipt point basis.

That's currently available. We think that's the

level of information that is important to know, what is the

capacity that you use to bring supplies into our system.

And to answer Ms. Cochrane's question again, we

think the three levels are: What's on‑system; what's going

to storage; and what's going off‑system.

The on‑system, again, is broken down at each of

these five zones, to tell anyone interested, what is

available at any time that they're looking.

And I think this is important with reference to

the explanations stated at Paragraph 50 of Order No. 720, in

which the Commission is saying, why are you looking for this

information; what are you going to do with it?

The example that's given at the end, for

example, in overseeing markets, the Commission routinely

checks for unused interstate natural gas pipeline capacity

between geographically distinct markets with substantially

different prices, as a sign that flows may be managed to

manipulate prices.

What we have available today, is capacity, the

amount of capacity that's available to bring supplies into

our system. We don't think there's any addition to

transparency that could be found, if you did have ‑‑ if we

did have, if you did have access to demand down to the

individual facility level.

The relevant inquiry is, what can be brought into

our system, how much is going into storage, how much is

going back off the system; that's the level at which we

think the information is valuable for the purposes you

stated.

MS. COCHRANE: For clarification on this, is this

available to anyone?

MR. ELLIS: Yes.

MS. COCHRANE: You mentioned that we have the

customer password on your website, and I just wanted to

clarify what's publicly available to anyone looking on your

website.

MR. ELLIS: It's the information I just stated;

it is publicly available. Anybody who wants to see what's

available in a particular receipt point, location, can do

so.

MR. REICH: Just to follow up with you, Mr.

Young, you talk a lot ‑‑ you've been using the terms,

"mainline receipt point, mainline delivery point."

From a regulatory perspective, is there some way

‑‑ can you suggest a way to define the term, "mainline,"

that you ‑‑ as a starting point?

MR. YOUNG: I think there's a ‑‑ we looked at ‑‑

there's a reg. I don't know the exact area, but it's

defined in the regs, and that was, you know, at the tailgate

of a gathering system, processing plant, you know, anywhere

at the ‑‑ where gas comes in from a grouped set of wellheads

and delivers into a point, and then, you know, the mainline

delivery points are the points, I think, where we deliver to

the LDCs or the industrial points.

And those are the pricing points. If you look at

where people trade off of, those are the areas that people

are looking at in the market. There's not any trading

points at wellheads or downstream; they're all at kind of

the interconnects on pipelines in areas or zones off the

pipeline.

MS. COCHRANE: Mr. Ellis, I'd like to ask you a

question about your Rehearing Request. You stated that the

posting information that we were requiring in ‑‑ are

requiring in the Rule, may violate state or other regulatory

guidelines, and I was wondering if you could explain more,

how you think that we might be conflicting with your other

regulatory requirements?

MR. ELLIS: Yes, that's a concern of PG&E's.

There is a tariff rule in PG&E's tariff, that requires them

to maintain the confidentiality of customer‑specific,

commercially‑sensitive information, and that's the

reference.

MS. COCHRANE: Okay, so it's just limited to

customer‑specific information, and likely went to the

location named?

MR. ELLIS: That's correct. Both PG&E and the

SoCal Gas SDG&E joint system treat information concerning a

customer's individual nominations or flows, as confidential

and commercially‑sensitive, and PG&E also has a tariff rule

approved by the CPUC, that requires them to maintain that

confidentiality.

MS. COCHRANE: Thank you.

MR. YOUNG: And just as a followup, the reg is 18

CFR 157.202‑65.

MR. ELLSWORTH: This question is for Mr. Young.

You talk a little bit about gas control. I was kind of

wondering whether you could expand on exactly what type of

information they see. I think you mentioned line pack, so

they can look at pressure.

But do they actually ‑‑ are they also looking at

flows across large meters, or pool points, or what kind of

information are they actually collecting?

MR. YOUNG: Gas control, they get SCADA feeds, so

they'll see the real‑time activities on the pipe on

different points.

I like to call it ‑‑ they get a dispatch, if you

will, every day, so the Nomination Scheduling Group will

take the orders from the customers, where all customers

bringing gas in at these receipt points, taking to these

delivery points.

The scheduling system will aggregate all that

together, and, at a point‑by‑point level, tell them, these

are the nominations, the schedules, or the confirmed volumes

at each of these interconnecting points.

And they are usually what I call the mainline

receipt and mainline delivery points. That's what they're

looking at.

Gas control will get that, they'll have their

SCADA screen, they'll know that I've got nominations of 150

million at this point, they see SCADA real‑time, and they'll

see what they're doing, every day, and that's how they will

manage their pipe.

There is also a set of alarms, and they'll have

line pack estimates. They'll look at pressures, so there

are pressure alarms all throughout the pipe.

They manage ‑‑ you know, every gas control group

has a different set of SCADA screens, but they'll look at

the points that are relevant to them, alarms will come up,

and they'll manage accordingly, whether compressor stations

are running, and if something happens, the line pack drops

in one area, they might have to turn on a compressor to

bring more gas in from other areas, to make the

determination whether to bring gas in or out of storage.

Usually, their job is, can I ride this out,

without having to do anything, or do I need to make some

kind of adjustment to the system?

Sometimes that adjustment goes back ‑‑ comes back

to the scheduling group, which says, hey, we either need to

cut some nominations, or we need to get more gas brought

into the pipe, because we can't fill it with our current

line pack.

MR. QUINN: Can you explain what the scheduling

protocols are for flows off‑system. You mentioned that one

of the places that gas can go, is off‑system. How does

scheduling work for those flows?

MR. ELLIS: I'll try to. With reference to the

nomination model at page 10 of the presentation materials,

there's a box or a circle for OSD off‑system deliveries.

Currently, on our system, our customers can nominate

supplies for delivery to PG&E.

That nomination will be confirmed by the system

operator and the gas will flow off‑system. We do not have

CPUC authority to confirm nominations for deliveries back to

the interstates. For example, if you look at the map to the

Transwestern System, at Needles or to the El Paso System at

Topac or Aaronberg, when we receive that authority from the

CPUC, then we will be able to confirm nominations and those

volumes will be confirmed, and the aggregate of those

volumes is what we would propose as one of the three

elements at the level of detail of information that would be

of most use to anyone wanting to watch actual system

operations and demand and available capacity on our system.

That would be the aggregate of off‑system

deliveries, the aggregate of on‑system and deliveries to

storage. Storage is currently available and capacity is

currently available.

MR. QUINN: Could you explain why you think the

aggregate is the right number, rather than, say, deliveries

to within‑state, to PG&E and deliveries back to the

interstates, in general?

MR. ELLIS: That's a question at a level of

detail I have not considered. The question is, for off‑

system deliveries, why isn't it relevant to know, to

individual pipelines? It may be; I don't have an answer for

that question.

MR. QUINN: Thank you.

MS. COCHRANE: Oh, please go ahead.

MR. MURRELL: This is really for Mr. Young, but

also a little bit for Mr. Ellis. Mr. Young, you had a very

specific proposal to make a change.

Under your proposal, for your company, how many

points would end up having information reported, and how

does that compare to the number of points you believe your

company would have to report under the existing rule?

MR. YOUNG: We didn't do the analysis of the

exact numbers, but if you look at the couple thousand meters

that we have on our system right now, a majority of which, a

design capacity, it could be argued, would be 15 million or

more. We have a lot of four‑inch meter runs in the pipe

that are, again, not pulling much, so virtually, you know,

75 to 80 percent, maybe 90 percent of the meters, would be

reported under the design capacity, if we argued that was

how to go.

If we didn't see that, that number would

probably drop significantly. I would say we would have ‑‑

gosh, I'd have to put a pencil to it, but, you know, a

hundred or so.

I mean, don't quote me on that, but it would be a

lot smaller, but the thing that we thought, was, you're

going to capture the same data, the same, and, I would

argue, more accurate data, with less meters, because then,

when we go through the design, identifying what meters do we

post, that's been a big question that we've had.

We've tried to do that, and we've had lots of

meetings with engineers and said, okay, let's get all the

meters and go through it, and right now, we're in the

process of identifying it one‑by‑one, based on pressures and

orifice plates, and, you know, rate of flow.

And that's the max that we can possibly do.

We're going to have a lot of meters out there that are never

going to flow more than 15 million a day. If we do, the

average flow will capture those, and that's why we want to

do the ten‑day heat, because, yeah, we'll have more meters

there than ‑‑ we'll have a lot of meters where they're not

going to flow 15 million for, you know, more than, you know,

maybe 30 days a year, but it's more conservative, but you're

not going to have the big gap between all this excess

capacity being shown, and what's really there.

So we just want to do something to get the right,

most accurate number. And, you know, this doesn't

necessarily have to be the exact way to do it, but it was a

proposal to say, it seems to make more sense, and I think

most companies, at least in the TPA, they go to measurement

groups and they have measurement data.

Then they can do that query pretty simply, and if

it feels comfortable that that's correct, and then it's just

a matter of some pipelines would have to aggregate those to

the virtual points; some pipelines would not, because they

don't have virtual points.

But they could ‑‑

MR. MURRELL: In terms of the types of dynamics

that you see on your system, from one year to the next,

would you expect to see many changes in terms of points that

become eligible under your screen, in the next year or the

year after that? Would you see a lot of points dropping off

and being added to the list?

MR. YOUNG: No, I don't think there would be a

lot ‑‑ there shouldn't be a lot of points added. I mean,

there would be new points and new production that came on,

or new delivery points. If we had power plants, certainly

we'd do that.

In terms of meters dropping off, if we had

wellheads that have declined, but those would be pretty big

wellheads, if we're doing 15 million a day, so I don't see a

lot of changes. That's why we thought the yearly would be a

good number, because you wouldn't see a big change from year

to year; you'd have a consistent path throughout the year.

MR. MURRELL: Okay, thank you. Mr. Ellis, you

had kind of articulated a proposal that, in my mind, I was

trying to quantify in the same way. Do you have a sense of

what the impact would be, in terms of the number of points?

MR. ELLIS: Yes. The proposal I have, would

identify deliveries and capacity available at our receipt

points, with our interstate systems and with California

producers.

It would identify receipts or withdrawals from

storage, net aggregate, on a daily basis, and the difference

will be on‑system demand, on‑system usage.

We have that information available, readily

available today, so posting a separate screen that provides

it, is something we could do.

I'm not sure, Mr. Murrell, I caught Mr. Young's

proposal exactly. I did hear the part about looking at

average flows over the largest ten days, to identify the

15,000 MMBtu criteria. I did not gather, if he was speaking

exactly to nominations at those locations, or to deliveries

at those locations.

MR. YOUNG: It was based on physical at those

locations, physical deliveries.

MR. ELLIS: Thank you. We would not propose any

statement of data based on actual flows or measured flows.

For one thing, to begin with, you'd have to have the

capacity to do that, and that would be a costly undertaking,

or could be a costly undertaking for many systems.

But, even more fundamentally, I don't see the

value with respect to the Commission's transparency goals,

which we very much support. But I don't see the value with

respect to the Commission's transparency goals, in measuring

actual flows to locations of a particular size.

MR. YOUNG: Let me clarify. I wasn't saying to

post actual flows. I was saying to use actual flows to come

up with the meters to post.

So, yeah, I agree, we wouldn't want to post

anything, any actual data, daily, because that would be just

‑‑

MS. COCHRANE: Just to clarify, too, I had

written down that you were talking about points where you

schedule and that would include the pools. I thought you

were talking about pool meters.

MR. YOUNG: Right, so you would have the ‑‑ if

somebody scheduled to the pool meter, those are oftentimes

an aggregation of a number of wells.

MS. COCHRANE: I'm sorry, a pool meter, as

opposed to, like, a pooling point. Virtual points?

MR. YOUNG: I guess it depends. Some pipelines

follow the pool meter; some people call it a virtual point.

It's kind of a paper aggregation point that people nominate

to, and, at the end of the month, a number of meters are

combined to show that's the volume at that paper point.

So the design capacity that I was ‑‑ or the

capacity I would look at, would be those meters, summed up.

If they were more than 15, then we would have a capacity

that we could compare the schedules next to on a daily

basis, but I wouldn't want to post any actual data every

day.

MR. PETERSON: Just so I can confirm, that would

apply both to receipt and delivery points; is that correct?

MR. YOUNG: Yes.

MR. PETERSON: But you couch that in terms of two

points that, I guess, are scheduled now?

MR. YOUNG: Right. I call them the commercial

scheduling points. They are points where people ‑‑ where

shippers do their nominations, and they come into our

systems, saying, I'm bringing gas from this point and taking

it to this point.

Those are often those virtual points. They don't

schedule at the hundred meters behind there; they nominate

at that one virtual or pool point, and so they would have a

nom of ‑‑ you know, as an example, if they had 100 meters

and they all did 100 Mcf, that would be 10,000 that they

would nom at that virtual point.

At the end of the month, they would sum all the

measurements at those points, compare it to the schedule to

allocate.

MR. PETERSON: And under the ‑‑

MS. COCHRANE: Bridgett.

MS. SHAHAN: I was just going to say, I guess I'm

a little bit confused, but if it's a virtual point, a paper

pool, we don't have any design capacity. It's just, for

Nicor and Natural, it's Natural's point, too, it is the

Chicago city gate at Nicor, and it is covering 75 actual

points that interconnect between Natural and Nicor, so

there's no design capacity in that.

So if you want to know what's scheduled on

Nicor's system on a daily basis, we can tell you that, and

it is the information that we get from the pipelines. It's

the pipelines' meters, it's the pipelines' reporting, and

that will be two virtual points, one for Natural, one for

Midwestern, and then several for the other ‑‑ that are

actual, physical interconnects with the other pipes.

I think there's about 13 others, and we know

what's scheduled there, and it's because the pipelines tell

us what's scheduled there. And if you want what actually

flows at all 96 interconnects, we know that, too.

But they're ‑‑ I'm just saying that they are kind

of two different ‑‑ they're very different worlds.

MR. PETERSON: So, currently, on your system

right now, we can look at interstate natural gas pipelines ‑

‑ and we do every day, and we see how much gas is delivered

to your city gate off Natural and other pipelines.

MS. SHAHAN: Correct.

MR. PETERSON: And so we see that. What we don't

know, is if Nicor has a massive market area gas storage

capability, for example, and some of that is not all

pipeline‑owned storage, and so you can solve your demand

each day in that market, by relying on that.

I guess Mr. Ellis's in California, we know what

that number is, currently, on SoCal and on PG&E. I don't

know that we know what that number is, say, for Nicor, in

terms of the contribution of storage withdrawals on a given

day. We see the Chicago city gate price has maybe doubled

or whatever, because it's cold, we know what's going through

the pipelines, but the pipelines will get constrained,

they'll get max'd out, and there will be a large withdrawal

capability probably brought to bear by Nicor.

And so from an oversight standpoint, we don't

have that window right now, to understand what's going on.

MS. SHAHAN: And we don't have that on a daily

basis, either. I mean, it's the end‑of‑the month figuring

out with the schedules, again, and on our system, our

transportation customers are scheduling to their pool, to

their contract, or they're scheduling into storage. That's

basically the choices they have.

And at the end of the month, we figure out all

their customers that are covered by their contract, whether

it's just themselves or thousands, and coordinate, like,

well, you had this much storage this month and you've

ratcheted down to here, or you're up to here, and it's

definitely a lag of knowing, of dealing with all the

paperwork.

I guess the easiest way to say it, is, it's the

control room deals real‑time and makes it work every day,

and then a month later, all the paperwork is figured out, of

who did what.

MR. YOUNG: I mean, I would classify the LDCs,

just like the gathering. I mean, I do think you get most of

the data that you need, from the interconnect delivering to

them.

And if they do have a storage pool, eventually

that gas has still got to get back there, so the gas going

to the LDCs, is coming through the mainline delivery points

at some point, just like on the gathering side.

MS. COCHRANE: I don't think Staff has any other

questions. Do any of the panelists want to say anything in

addition, or clarify anything?

(No response.)

MS. COCHRANE: Okay, all right, why don't we ‑‑

no problem stopping early. So why don't we take a ten‑

minute break and then we'll start with Panel III, so let's

come back at 11:30. Thank you.

(Recess.)

MS. COCHRANE: All right, thank you. Why don't

we start? This is the third panel, addressing the cost of

compliance. Again, we have John Ellis joining us again, and

Will McCandless, Director of Pipeline Portfolio, Commercial

Operations with Enogex, on behalf of the Texas Pipeline

Association.

Thank you for agreeing to speak on this panel,

and I was wondering, do either of you care to go first?

Okay.

MR. McCANDLESS: Well, thank you. First, I'd

like to, you know, thank the Staff, you know, for allowing

me to be here and to speak to some of these issues. I

appreciate the opportunity.

Again, my name is William McCandless. I'm a

Director at Enogex, an Oklahoma company. My primary

responsibility is, I'm ‑‑ one of my primary

responsibilities, is to manage and direct the Volume Control

and Scheduling Group, so I have a lot of experience, and

this Rule will have some impact on the day‑to‑day function

of me and my staff.

I'm here today to talk about the cost and effort

to implement Order 720 and maybe some proposed changes that

would allow us to better implement it, more cost‑

effectively.

I still believe there is still much that is vague

about the Order, and there's some confusion on actually how

to implement it. We are in constant talks with engineers,

internally, on what does this mean?

I think you've heard some statements earlier

about a four‑inch meter run, could, theoretically, get

15,000 MMBtus through it on a daily basis.

On the Enogex system, that would be about 5,000

meters, 5,000 to 6,000 meters, so it would be a significant

reporting requirement for our company.

Our members have estimated the cost to

implement, and the timeframe, based on some very basic

assumptions. These assumptions will have the impact to

actually reduce our costs.

The first assumption is that reporting will only

occur at nominated receipt and delivery points. This would

also include virtual points.

This also includes those meters, those virtual

points and meters downstream of just gathering and

processing facilities, so the Enogex system and many of the

interstates, have gathering systems that feed our intrastate

systems, and we receive gas from multiple locations.

I think you used the term, "city gates," prior,

and if we can minimize the number of those meters that

actually have to be reported, that would greatly reduce our

costs.

We will not be ‑‑ another assumption is that we

will not be required to change our current nomination and

contracting processes. I think one of our big concerns ‑‑

we've implemented systems, we've implemented processes to

really manage this day‑to‑day business, this month‑to‑month

business.

We're really hoping that the impact of this

reporting, does not have a significant change in the way we

contract today and the way we manage our business today,

from the day‑to‑day nominations management.

We're also asking that ‑‑ we're also assuming

that the posting is only required on standard business days.

Many of the intrastates, many of the members of the TPA,

don't necessarily staff a weekend volume control group.

We may have a weekend gas control that manages

the physical aspects of the pipe, but as far as the

scheduled aspects and managing the contracts and the

nominations, that tends to be a normal business‑days

function, and requiring us to report on a weekend or on a

holiday basis, would mean we'd have to increase our staffs,

therefore, our costs.

I understand that an estimate of $30,000 was

included as the cost to implement the Order 720. This is

the number I emphatically disagree with, even with the

assumptions I noted previously.

There were no members of the TPA that actually

introduced or provided numbers in that neighborhood.

Based on information provided by TPA members,

average costs to implement, again, assuming these

assumptions, was $100,000, with a $50,000 a year annual cost

to maintain.

Some of our members' actual startup costs are

much higher, because they're starting from scratch. They're

not as technical or they don't have the technology in place.

There's an initial technology they're going to have to

implement to better facilitate the scheduling and

aggregation of scheduling information.

Included in these costs, were hours for ‑‑ and

this is under implementation ‑‑ was the IT group to collect

business requirements, develop and then implement a

solution; for users to go through an acceptable ‑‑ through a

period of acceptance testing; legal hours for consulting and

reviewing of the business requirements to ensure a solution

meets FERC reporting requirements.

Because there's no safe harbor in this Rule,

there is potential liability, and because of that, our

internal audit and our external audit, are going to want to

get involved. This means we're going to have to develop

SOCs controls, business processes; we're going to have to

document those controls, to ensure that behind the scenes,

even though, as we're reporting, that there's documentation

from managers and from the people actually doing the work,

that they've checked off the box and they're actually doing

what they're supposed to be doing, and that they are

verifying the numbers, as appropriate.

The fact that, again, that it is a potential

material liability, forces us to go through this audit

process.

The commercial groups will need to communicate

with our large end users and producers, informing them of

the new reporting requirements under the new Rule, and we

expect many of our customers will argue confidentiality.

Many of our large end users have confidentiality agreements

or clauses within their contracts.

Right now, we know that that's going to be a

touch point for many of our customers, and it's just going

to require additional time for commercial, to actually walk

them through the Rule and why this is happening, so it's

just additional time.

And, finally, there are some direct costs

associated with computer hardware and software.

On an ongoing basis, IT maintenance associated

with the new hardware updates, software, system upgrades,

and replacements, there's ongoing monthly SOCs control

documentation and testing that needs to go on.

Executing the actual data exports, verifying and

then posting, if you, you know ‑‑ and, again, this is an

area where, if you had 6,000 meters you had to report

against, versus ‑‑ it's one number, versus if it was 150

that you could verify against, that's another number, so,

again, for us, we prefer the lower number that would

include virtual points that I think were mentioned

previously.

And, finally, there's no doubt that the changes

that you've made in this latest Order, to move away from

actuals, benefitted us greatly. It reduced the costs

greatly, and we appreciate that.

However, the $150,000; $100,000 for

implementation and $50,000 for ongoing, still remains very

material, a very material expense for many of the members of

the TPA, including my company, Enogex.

In the past three months, my company, just to

give some flavor, has gone through staff and salary

reductions, hiring freezes, and severe budget cuts, so we

appreciate your consideration and thank you for the time.

MS. COCHRANE: Thank you. Mr. Ellis?

MR. ELLIS: Thank you. For San Diego Gas and

Electric Company and Southern California Gas Company, first

I want to say that we very much support the Commission's

price transparency goals.

We have an electronic bulletin board that has a

great deal of information available today, and the first

question that we face in trying to come up with an estimate

of costs for compliance with Order 720, is to understand

what it is that the Commission would want to see from our

systems, in addition to what we have already.

One logical interpretation of Order Number 720,

would ask for a listing of customers who have meters of a

certain size, first, the identification, the list of

customers, would have a meter with a delivery capacity of a

certain size.

We do not currently have that functionality

today. The point that I would make there, is, if that

information were provided, along with a format that would

indicate scheduled volumes to each of those customers or

locations, the numbers that would be posted next to it,

would be zero.

What would be the cost to set up a screen or a

board that listed the number of customers and present next

to those customers, on a daily basis, what are the

nominations for all of them that would be zero.

There would be a cost to come up with that list,

and I don't see any benefit to posting zero next to it every

day, and that is, in fact, what the information would be for

SoCal Gas and SDG&E.

The second would be to identify nominations at

the pool level. In my presentation for the second panel, I

mentioned the fact that most nominations are handled through

contract marketers or through accounts with multiple

facilities behind them.

There would be another cost, different from the

first, if the idea were to identify and provide a nominated

daily number for pools. That could be done. It would come

at another cost, and that cost would be less than a cost to

identify and list individual customers with a meter capacity

of a certain size.

There, I question the value of having nominated

daily information for pools, for pooled accounts.

The third would be the information that we

proposed in the second panel, and that is the aggregate of

on‑system demand, on nominations to storage, that is, in the

aggregate, what is being injected or what is being withdrawn

on a net basis from storage, and off‑system deliveries,

whether that's an aggregate of all off‑system deliveries,

or, as Dr. Quinn suggested, off‑system deliveries to

individual locations.

That number I think would be significantly less

for us, and that is primarily because we already have much

of this information available. So that third proposal is

one that could be accomplished at a reasonable cost.

We have, as part of the presentation materials,

an estimate from PG&E that is stated in terms of hours

rather than dollars for startup costs. I believe their

estimate is for the first of the three levels I proposed.

That is, what would be the estimated startup burden in terms

of hours to develop a screen or a listing of all delivery

locations with a meter capacity of a certain size.

But again, for PG&E I believe the information

that would be posted next to each of those listed customers

or locations, while it would not be zero as it would be for

SoCalGas and SDG&E, it would be essentially a meaningless

number because each of these customers enjoy balancing

flexibility under their CPUC‑approved transportation rates

that do not require them to nominate the volumes on a daily

basis to individual facilities.

That said, I believe the estimate that PG&E has

presented is the most detailed of the three levels I

propose.

I would also note that we are speaking about

SoCalGas and SDG&E as one EBB. PG&E's Pipe Ranger System is

another. Those are systems that have been in place for more

than 10 years. They have a lot of functionality, a lot of

information that is already posted.

I am sure that the startup costs for other AGA

member companies would be quite different, but I wanted to

present this information on behalf of the companies I was

asked to speak for.

Thank you.

MS. COCHRANE: Questions?

MR. REICH: Just a quick clarification,

Mr. McCandless. The $150,000 estimate, is that based

on‑‑that is based on your understanding of what is currently

in the Order? Or perhaps some kind of continuum to clean it

up?

MR. McCANDLESS: I think it's a continuum to

clean it up, because I think the way it is currently written

to require posting of information at meters greater than

15,000, and the fact that our businesses, even though we

flow‑‑you know, we have numerous, in our company 90 percent

of our meters meet that requirement. But we don't nominate

at that level.

So there is no scheduled information necessarily

at that level. And so the assumptions we were making is

that what you are really looking for is schedule

information. You're looking for the aggregate of that

information at market points, or at points where wholesale

gas is bought and sold.

So we believe what you're really looking for is

maybe the information at the virtual point. And so if we

can get to the virtual point, that data is readily

available. That is how we conduct business today. I think

many of the intrastates support pooling, or one form of

pooling, and if they don't they do it at the meter level,

which they would report at that level.

So that is our preferred method. And again I

think one of the questions that was asked was how to reduce

costs. And for us, if we could report at the pooling level,

or at the virtual meter level, that would be one significant

method to reduce costs.

Did that help?

MR. REICH: Oh, yes. And also you described your

process to develop the posting system. Can you‑‑do you have

a sense of how long that process would take, say shortest to

longest?

MR. McCANDLESS: Shortest to longest? You know,

there's Enogex and what I think we can do, and I think

there's‑‑but, you know, there's the companies within TPA as

well and all the other intrastates. I think you would find

a wide variety of technical capabilities and a wide variety

of systems and capabilities within their companies.

Enogex, I believe the 150 days, based on these

assumptions, based on a more simplified but using a virtual

pool is probably doable. If you start looking at actual

meters, or we could get information up on the web just like

John Ellis has said, but it would be meaningless.

If you require schedule information, it would

entail us changing our business practices to require our

customers to start scheduling, which I think for our

customers would be a nightmare. We would go from dozens and

hundreds of nominations to tens of thousands of nominations.

And I don't even know if our systems could handle that type

of load.

So it would require significant changes to

systems, significant effort, and it would almost be

inestimable. We would be back up in the million dollar

range again.

MR. REICH: And I know that SoCalGas and PG&E

have their own systems going, and various interstate

pipelines and I'm sure some intrastate pipelines have some

kind of posting process. Are there any‑‑or are you aware of

any packages, or is this all internal development based on

the estimate of kind of how long it will take it to put it

together? Or is there a contracting element there?

MR. McCANDLESS: There can be‑‑most of ours would

be internal. I know there are third‑party BBS types that

provide that as a service, so that all you have to do is

provide the information to the BBS.

I think getting the information up to the web is

the least‑cost part of it. I think that technology is

pretty well established. It's the aggregation of the

business data itself, and it's pulling it into a format.

It's the definition of what the capacity is. It's the

definition of available capacity. It's pulling all the

meters, making sure that you've pulled all the meters that

meet the requirement, and that you're doing this on a daily

basis potentially numerous times, depending on the number of

cycles you support, or the number of times you make changes

to your nominations.

So I think it is the actual pulling of the

information and the methodology of that that entails most of

the cost. Getting it up on the web is not near‑‑it's a

well‑established technology.

MR. ELLIS: For SoCalGas and SDG&E I don't know

the answer to your question. I don't know to what extent

there are packages available that could be used as a base or

a floor for individual systems EBB.

I do know that we spent a great deal of money, I

believe in the millions, to get our system revised as of

October 1st, 2008, to provide the detail with respect to our

firm access rights system, but I don't know to what extent

that was based on a model or a base that's available

commercially.

MR. PETERSON: Mr. McCandless, on the‑‑we concur

with your general thought in terms of I was involved in

looking at some cost issues involved in comporting with this

rule, and it was our presumption that many of the potential

covered parties by this had information on their operations.

And in fact many of the potential parties that

would be covered by this rule, some of them have interstate

natural gas pipeline companies under their holding company

umbrella. This is a standard thing they already do. So

this is not a new thing for some that would be covered by

this rule.

And as you note, you can go to‑‑there are

software companies in Houston and elsewhere that specialize

in offering EBB systems, informational posting systems, akin

to what the interstates already do. It is kind of a canned

thing.

Our understanding is that is not terribly

expensive. But your comments I think are helpful to us in

noting that. So that side of things we didn't anticipate,

frankly, to be that costly.

But the process issues in taking what some

parties have currently and then transferring that into, you

know, a publicly disclosable format, that is something we

were trying to get more information on today. And we

suspect that there's a lot of variability in terms of the

capabilities of different parties to do that currently, as

well.

So anyway, I wanted to note that. In terms of

the timeline, I think TPA said that one thing they might be

seeking in comporting with this is, aside from the cost

issue, is do the challenges of, at least for some of their

members in gathering this information, you might need

additional time to come into compliance with the rule. And

that is something that, if so, we would like to hear some

more specifics about, about what is entailed with that.

So I don't know if you have those thoughts now.

Those comments were noted in Rehearing, and we saw them.

MR. McCANDLESS: I can speak to a little bit.

And I think you make a good point. But even a company that

has interstate and intrastate business‑‑I'm going to go back

to your first one first‑‑it is true that the mechanism to

get information from the systems up to the web is in place

and that they could leverage that technology, that

expertise.

What may be misunderstood, or not fully

appreciated, is the business paradigm, the business

processes, the way that the intrastate conducts business may

not marry well with the way the interstates conduct

business. And so it may not be a simple one‑to‑one

translation.

There are some assumptions, and I make some of

those in here about virtual pools. A lot of the intrastates

and city‑gates rely heavily on virtual pools to deliver gas

to our end users, to pool gas from gathering systems. For

example, at Enogex we don't have receipts at the‑‑we have

six or seven processing plants with stubs. We don't

necessarily receive gas from those on a scheduled basis

individually.

We have one major receipt point from the

gathering system that's an accumulation of all the tailgates

of the plants as well as gas that's directly brought in

that's not processed. So it's a virtual point, and that's

where the scheduling begins.

And so that's a little different than maybe what

you would expect from an interstate.

As far as costs, it is really a function of

narrowing down the rules. Right now it is up in the air

because we are still unsure as to what we're going to

actually have to implement. It's a function of, you know,

are we going to have to live with the 15,000 a day rule?

And what does that mean, even if we post meaningless

information up on the web?

You know, we don't really want to go there. We

really want to provide the most meaningful information to

facilitate the transparency that you all are looking for,

and that the market desires.

So‑‑and again we are proposing some solutions

for that. But if it's required to change our business

processes, or if you're looking for much more information

than we currently are estimating, the cost estimates could

go up ten‑fold, and the time estimates could go up ten‑fold

as well. It could take multiple years.

Again, it is a function of our systems as well

that are in place.

MR. PETERSON: Mr. Ellis spoke earlier about the

existence of the PG&E and SoCal systems that are long held,

and people have relied on those. Do you‑‑I will presume you

are familiar with those, but you have information now in

terms of solve your network each day.

MR. McCANDLESS: Um‑hmm.

MR. PETERSON: I guess what challenges would

there be if you're not doing a detailed daily version of it

by point, but you're doing something more rolled up than

that, what‑‑I mean, how does that affect your time line to

roll something out and your costs associated with that?

MR. McCANDLESS: We‑‑

MR. PETERSON: And what information do you have

now that you could bring to bear to provide the market with

a clearer picture of‑‑you know, the Oklahoma market is kind

of a place where we do not have very good demand

information, frankly. And so what exists already that would

be ready to go that you could implement in a system that

would shed more light on that?

MR. McCANDLESS: Very quickly, what we can

implement very quickly would be a system where we reported,

again, the virtual meters, the pools where we weren't

necessarily required to report at the actual meter level.

Most of it, we do balance our system daily. We

go through a process every day. We balance the system

daily. That doesn't mean everybody is in balance; it just

means we compare our noms to actual flows.

Those actual flows may be‑‑again, it may be the

sum of 100 different wells. And so I may be measuring a

customer, a customer may have nominated 200, or 20,000

MMBtus. Their actual flow of the 100 wells might have been

20,257. And so, you know, they're building up an imbalance

in one direction.

Part of the job of the volume control group is to

monitor those to keep them within a reasonable tolerance,

and then bring them back. And then, if needed, request

action to bring‑‑request action of the customer to bring

that back in balance.

So it is being monitored daily. We have got a

lot of good information on a daily basis at the scheduling

and contractual level. I think the struggle I have is, when

you're looking to dive into‑‑some of the rule speaks to the

actual nature of the business, and I think the lady I think

from Nicor did a good job of saying there's these two

worlds. There's the nomination and contractual world where

you're balancing contracts. And then there's the physical

world that occurs underneath that that the gas control

groups manage. And the two worlds sort of live in parallel

and they balance. At the end of every month you try to get

everybody into balance, but the rule is sort of saying we

want to‑‑what I hear you saying is you want to see what's

going on at the scheduling level, that's where the market

lives; but what's actually going on at the actual level may

be different.

There may be some activity there that is not

representative of the nomination world, of the contractual

world.

MR. REICH: I just want to get back once again to

the estimate you gave earlier, the $150,000 estimate. In

that estimate do you include having to develop any kind of

operational data that you don't already generate? Or is

this all based on in a world where we're doing virtual

points?

MR. McCANDLESS: It's based on the world

primarily of virtual points where we identify the 150 or 200

wells‑‑or not wells, but meters, or virtual locations that

will have to be identified and have an engineer at this time

to actually come up with a number, what that theoretical

number is.

If we have to go in and identify the 6,000 or

5,000 meters, that number will grow considerably to have an

engineer sit down at each of those meters and back into a

design capacity would be extensive. We don't just‑‑that's

not an attribute that we keep with each of those meters.

MR. REICH: Thank you.

MR. PETERSON: And the reason why the potential

meter numbers are so high I presume is mainly because of

the‑‑is that more of a supply issue where you have lots of

wells that could flow up to a certain level each day, many

don't‑‑

MR. McCANDLESS: Right.

MR. PETERSON: So it's not a delivery thing,

mainly? It's really on your receipt side? Is that correct?

MR. McCANDLESS: That's correct. It's primarily

on the receipt side. A lot of it is‑‑you know, a 4‑inch

meter tube is sort of standard 4 to 6 inch on our system,

it's sort of standard. If you could 15,000 through it, you

know, you may have a well that comes on, and again the way

the decline rates work, you may have a well that may come on

and the very first day produce 15‑ or 18,000, so you see the

meter run for that size, but very quickly, inside that

month, and then from that point forward for the rest of the

life of that well, it's going to produce significantly less

than that 15,000 a day meter. It will produce, you know,

1,000 to 2,000 a day. And again, we would like to avoid

having to report‑‑I think in reporting it, it is just going

to be superfluous information that you would otherwise get.

I think you would get more accurate information if you got

it at the virtual point.

Because at the virtual point you would basically

be netting all the gathering meters. I don't know if that

makes sense or not. Versus just the ones that are of

significant size.

MS. COCHRANE: Any other questions?

(No response.)

MS. COCHRANE: Okay, thank you.

As I said, there is no reason why we can't end

early, especially since it is lunchtime. I want to thank

everyone again for coming, and especially the panelists. I

really appreciate some of you traveling here, and hopefully

the fog has lifted and when you leave you will get a nice

view of the Capitol as you leave, instead of the fog we had

this morning.

What I would like to do is, there was a proposal

that was presented by the TPA during the panel presentation.

So there are a couple of things I would like to do.

I would like to provide a 10‑day period for three

things to happen. I want to narrow what we receive at the

end of the 10 days, which is March 30th, but first off there

were a few panelists who provided‑‑Mr. Ellis, you provided a

Power Point. Then there were two maps that were provided.

If you could please file those in the record in

this proceeding so that others have it. I know that the

Southwest one you might have to scan that since it had some

handwritten things on it, which was fine. But if you could

please put those in the record I would appreciate that.

Also, if any panelist wants to correct the

record. I don't want to open it up to a lot. This was

really intended to get operational information, not more

legal argument or anything, but if anybody wants to correct

the record of statements that were made when you go back and

think about it, if you think you made a misstatement that

you would like to correct, please do that.

Then also I would like to ask the TPA if you

could provide a written statement of this proposal. There

was some discussion back and forth. If you could just

clarify so that it is more clear what the proposal is.

At this stage of the proceeding, we do have a

Final Rule. We have Requests For Rehearing that are already

filed. We are in the Rehearing stage. So it was not the

intent to get more proposals. However, you know, the

Commission wants to make this work and we want to have a

rule that works.

We did grant an extension of time for compliance

with the Rule, so we have some time to think about it and

make sure that we get the information that we need. As

people have said, we get valuable information and meaningful

information.

So Staff will take everything that we have heard

so far and make a recommendation to the Commission. If the

Commission decides that this proposal is something they want

to consider, then we will have to go through Notice and

Comment Procedures under the APA at this point.

So I would not want this 10‑day period to be a

time for people to respond to the proposal because right now

this is Staff. But, you know, if the Commission is to

consider it then there will be an opportunity for Notice and

Comment. We will put it in the Federal Register for all of

the members and people since this does address a lot of

entities who are not normally under our jurisdiction and we

want to make sure that everybody has an opportunity to see

the proposal and comment on it, and not just those of you

who are here at the technical conference.

So does that make sense, Gabe? Does that make

sense Mike?

(Nods in the affirmative.)

MS. COCHRANE: I'm checking with my attorneys to

make sure I'm properly stating how we are going to proceed

under the APA.

So with that, I thank you all very much. Take

care.

MR. ELLIS: Thank you for the opportunity come

here today.

(Whereupon, at 12:17 p.m., Wednesday, March 18,

2009, the technical conference was adjourned.)